CHAPTER 59. GAS SERVICE

§ 59.1. Definitions.

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

   Class A meter—A diaphragm displacement meter having a rated capacity of not more than 500 cubic feet per hour at 1/2 inch water column differential pressure and operating at a gauge pressure of not more than 15 pounds per square inch and not greater than the maximum pressure rating of the meter expressed in pounds per square inch.

   Class B meter—A diaphragm displacement meter having a rated capacity of more than 500 cubic feet but not more than 1,500 cubic feet per hour at 1/2 inch water column differential pressure and operating at a gauge pressure of not more than 15 pounds per square inch and not greater than the maximum pressure rating of the meter expressed in pounds per square inch.

   Class C meter—A diaphragm displacement meter having a rate capacity of more than 1,500 cubic feet per hour at 1/2 inch water column differential pressure or a displacement meter operating on a gauge pressure of more than 15 pounds per square inch gauge, regardless of rated capacity.

   Combined percentage of error—The sum of the percentage of errors of a meter and its associated instrument or auxiliary device.

   Cubic foot of gas—According to purpose, as follows:

     (i)   Testing. For the purpose of testing gas, that amount of gas which, if saturated with water vapor at a temperature of 60° F and subjected to an absolute pressure equal to 30 inches of mercury at 32° F (14.73 pounds per square inch), occupies a volume of one cubic foot.

     (ii)   Measurement of low pressure. For the purpose of measurement of gas to a customer taking gas at standard service pressure, that amount of gas which occupies a volume of 1 cubic foot at the time metered and under the conditions existing at the meter of the customer; except that where a temperature compensating device is built into the meter and the utility has received Commission approval for its use, the term means that quantity of gas which, at the pressure existing at the meter and the temperature corrected to 60° F, occupies one cubic foot.

     (iii)   Measurement of high or medium pressure. If gas is supplied to customers through orifice or other type meters at pressures above standard service pressure, that amount of gas which at an absolute pressure of 14.73 pounds per square inch occupies a volume of 1 cubic foot at the temperature base contracted for or established by the utility. Temperature correction, if made, shall be to 60° F.

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

   Customer meter—A customer meter is the meter that measures the transfer of gas from an operator to a consumer.

   Distribution line—A pipeline other than a gathering or transmission line.

   Fast meter—A meter which upon test has an average error exceeding 2.0% fast.

   Fast meter ratio—The ratio which the number of fast meters found upon test in a given year bears to the total number of meters tested in that year. Meters permanently retired from service shall be excluded from both the numerator and denominator of this ratio.

   First immediately preceding year—The calendar year immediately preceding the testing year.

   Gathering line—A pipeline that transports gas from a current production facility to a transmission line or main.

   High pressure—The gas pressure, expressed in pounds per square inch gauge pressure (p.s.i.g.) in excess of 60 pounds.

   Low pressure—Operating pressure, generally expressed in inches, which does not exceed 27.68 inches water column (one pound).

   LNG—Liquefied natural gas—A natural gas or synthetic gas having methane (CH₄) as its major constituent which has been changed to a liquid or semisolid.

   LNG facility—A pipeline facility that is used for liquefying or solidifying natural gas or synthetic gas or transferring, storing or vaporizing liquefied natural gas.

   Main—A distribution line that serves as a common source of supply for more than one service line.

   Medium pressure—The gas pressure, expressed in pounds per square inch gauge pressure (p.s.i.g.) between one and 60 pounds, and normally reduced by one regulator.

   P.S.I.G.—Pounds per square inch gauge.

   Pipeline—All parts of those physical facilities through which gas moves in transportation, including pipe, valves and other appurtenance attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders and fabricated assemblies.

   Pressure designations—‘‘Low pressure,’’ ‘‘medium pressure,’’ or ‘‘high pressure,’’ as defined in this section.

   Public utility—Persons or corporations owning or operating in this Commonwealth equipment or facilities for producing, generating, transmitting, distributing, or furnishing gas for the production of light, heat, or power to or for the public for compensation. The term does not include a producer or manufacturer of gas not engaged in distributing the gas directly to the public for compensation.

   Public utility service line—The pipe and appurtenances of the public utility which connect any main with either the point of connection of a service line of the customer if the line is provided by the customer in accordance with the rules and regulations of the public utility, or the meter of the public utility if the utility owns all the pipe and appurtenances between its main and meter.

   SMYS—Specified minimum yield strength:

     (i)   For steel pipe manufactured in accordance with a listed specification, the yield strength specified as a minimum in that specification.

     (ii)   For steel pipe manufactured in accordance with an unknown or unlisted specification, the yield strength determined in accordance with 49 CFR 192.107(b) (relating to yield strength).

   Service line—A distribution line that transports gas from a common source of supply to a customer meter or the connection to a customer’s piping, whichever is further downstream, or the connection to a customer’s piping if there is no customer meter.

   Slow meter—A meter which upon test has an average error exceeding 2.0% slow.

   Slow meter ratio—The ratio which the number of slow meters found upon test in a given year bears to the total number of meters tested in that year. Meters permanently retired from service shall be excluded from both the numerator and denominator of this ratio.

   Standard service pressure—The distribution pressure established by a public utility under the provisions of §  59.29 (relating to gas pressure requirements for low-pressure distribution systems).

   Testing year—The calendar year for which a public utility seeks to apply an extended test schedule.

   Test period—The maximum permitted time between the installation of a previously tested meter and the next test or between an in-place test and the next test.

   Third immediately preceding year—The calendar year immediately preceding the second immediately preceding year.

   Transmission line—A pipeline, other than a gathering line that does one of the following:

     (i)   Transports gas from a gathering line or storage facility to a distribution center or storage facility.

     (ii)   Operates at a hoop stress of 20% or more of SMYS

     (iii)   Transports gas within a storage field.

   The provisions of this §  59.1 issued and amended under Public Utility Code,66 Pa.C.S. § §  501, 1301, 1304, 1501, 1502, 1504, 1507 and 1508.

   The provisions of this §  59.1 amended through May 30, 1986, effective May 31, 1986, 16 Pa.B. 1901; amended July 3, 1997, effective August 4, 1997, 27 Pa.B. 3215; amended July 2, 1998, effective August 3, 1998, 28 Pa.B. 3050. Immediately preceding text appears at serial pages (232248) to (232251).

SERVICE AND FACILITIES

§ 59.11. Accidents.

 (a)  General. Each public utility shall submit a report of each reportable accident involving the facilities or operations of the public utility in this Commonwealth as provided in this section. The reports shall be addressed 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)  An event that involves a release of gas from a pipeline or of LNG or gas from an LNG facility and one of the following:

     (i)   A death, or personal injury necessitating inpatient hospitalization

     (ii)   Estimated property damage, including cost of gas lost, of the operator or others, or both, of $50,000 or more.

   (2)  An event that results in an emergency shutdown of an LNG facility.

   (3)  An event that is significant, in the judgment of the operator, even though it did not meet the criteria of paragraph (1) or (2).

 (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 the event of 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 as defined in subsection (b). Accidents reportable to the Commission which reports are also required by the Bureau of Workmen’s Compensation, Department of Labor and Industry, may be reported by transmitting a copy of the reports in lieu of a report on Form UCTA-8.

   The provisions of this §  59.11 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 1501, 1504, 1507 and 1508.

 (a)  Records. Each public utility shall keep a record which shall include data showing the time, duration and cause of each interruption of service affecting its entire system or a major division of its system.

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

 (a)  Pressure-recording equipment. If gas is measured to customers through displacement meters at a pressure greater than standard service pressure, the meters shall be equipped with reliable pressure-volume recording gauges or other devices for accurately determining the quantity of gas which has passed through the meter in accordance with contract or tariff provisions.

 (b)  Determination of multiplier. In computing the volume of gas at a given pressure base from a pressure-volume chart, the multiplier shall be obtained by the weighted average method, which consists of determining the average pressure for each indicated unit volume on the chart.

 (c)  Fixed pressure factor measurement. If the gas metering pressure can be maintained at a constant level so that it will not vary by more than plus or minus 1.0% of the absolute metering pressure, the quantity of gas corrected for pressure for billing purposes may be determined by multiplying the uncorrected volume by the factor of Metering Pressure Plus Atmospheric Pressure Divided by Base Pressure or by a special index with gearing to perform this calculation. The special index shall meet the specifications of ANSI Standard B109.1, §  6.2 (1986) or ANSI Standard B109.1, §  6.9 (1986). The ability of the regulator to maintain the constant pressure shall be verified at or prior to installation. Verification will be established by the use of a verified pressure-indicating gauge (accuracy: ANSI B40.1 Grade 3A), or a pressure-recording gauge, at both high and low flow conditions. When customer load is measured with a meter with a rated capacity of 1,500 cubic feet per hour or less, with metering pressure less than 3 psig, the performance of the regulator shall be verified in accordance with the test schedule of the downstream meter, established under §  59.21 (relating to meter tests). When customer load is measured with a meter with a capacity of over 1,500 cubic feet per hour or metering pressure of 3 psig or more, the performance of the regulator shall be verified at least every 5 years, except that those installed before January 1, 1990, shall be verified at least every 2 years.

 (d)  Determination of static and differential pressure. In computing the volume of gas at a given pressure base from an orifice meter chart, the average static pressure and the average differential pressure shall be determined for periods not exceeding 1 hour. If pressure variations are extreme during the hour, the average shall be determined for 15-minute intervals.

 (e)  Mechanical devices. Mechanical devices may be substituted for the method of computing orifice meter charts set forth in this section.

   The provisions of this §  59.15 issued and amended under Public Utility Code,66 Pa.C.S. § §  501, 1301, 1304, 1501, 1502, 1504, 1507 and 1508.

 (a)  Gas sold. Gas sold by a public utility shall be charged for by meter measurement, except in case of emergency, flat-rate street lighting, or if otherwise authorized by the Commission.

 (a)  Installation. Except as provided in §  59.31 (relating to service from production or transmission lines), a public utility shall provide and install at its own expense and shall continue to own, maintain and operate equipment necessary for the regulation and measurement of gas furnished to its customers. If meters or regulators not required by this section are furnished by the utility for the convenience of the customer, a reasonable charge for the meters or regulators may be made. Nothing in this subsection may be construed to require the utility to install regulating equipment on any gas piping system of a customer beyond the point of delivery at the meter outlet of the utility.

 (b)  Excess pressure protection. If gas is supplied from a high or medium pressure distribution system and the pressure is reduced to standard service pressure for use by the customer, the installation shall be provided with adequate over-pressure protection to prevent the pressure from exceeding 2 pounds per square inch in installations made on or before May 1, 1986, and the safe operating pressure for connected and properly adjusted gas utilization equipment in installations made after that date, in the event of a pressure regulator of failure.

 Meters shall be installed in either of the following locations:

   (1)  Inside the building, preferably in a dry, well-ventilated place not subject to excessive heat, and as near as possible to the point of entrance of the pipe supplying service to the building.

 (a)  Testing facilities. Each public utility shall provide and keep available the laboratory meter-testing equipment and auxiliary appliances as may be necessary to make tests required by the Commission. The apparatus and equipment so provided shall be of standard type, and measuring devices shall be accurate within normal laboratory limits and shall be available at all times for the inspection or use of the Commission staff.

 (a)  General testing equipment. Each public utility furnishing metered gas service shall own and maintain the equipment and facilities necessary for accurately testing the various types and sizes of meters used by such utility for the measurement of gas, unless arrangements are made to have the testing done in a shop or laboratory containing equipment and operated in a manner acceptable to the Commission. The accuracy of provers and method of operation will be checked periodically by the Commission. Alterations, accidents, or repairs to stationary meter-proving equipment, which might affect the accuracy of the equipment or the method of operating it, shall be promptly reported in writing to the Commission. The accuracy of testing instruments and equipment used as utility standards, such as dead-weight testers and precision type pressure gauges, which are used in the testing or calibration of meters or associated metering equipment will be checked periodically by the Commission.

 (b)  Equipment for testing small capacity meters. Each public utility shall own and maintain, except as provided in subsection (a), one meter prover of approved type and of a capacity adequate for the testing of small capacity meters. Each meter prover shall be supplied with accessories needed for accurate meter testing, be located in a room suitable for meter testing, and be protected from drafts and excessive changes of temperature. If the proving system includes automatic testing equipment or any mechanical devices to provide ‘‘read-out’’ capability—the entire meter proving system, including the basic prover, shall be maintained in good condition and correct adjustment so that it will be capable of determining the accuracy of any service meter to within 0.5%.

 (c)  Equipment for testing large capacity meters. Each public utility furnishing metered-gas service through orifice, turbine, or large displacement meters—except as provided in subsection (a)—shall have available and maintain in proper adjustment test equipment suitable for determining the accuracy of any orifice or large displacement meter used by the utility to within 0.5%. If the public utility uses a transfer prover standard for testing large capacity meters, the accuracy of the transfer prover and the method of operating will be checked periodically by the Commission in conjunction with all prover tests.

   The provisions of this §  59.20 issued under Public Utility Code,66 Pa.C.S. § §  501, 1301, 1304, 1501, 1502 and 1507.

 (a)  Test schedule for other than Class A, B and C meters. Each public utility shall make and record tests of orifice, rotary displacement and turbine type service meters as follows:

   (1)  Orifice meters shall have their differential and static recording gauges tested at least once every 2 months, the diameter and condition of the orifice plate checked at least once every year, and the specific gravity of the gas determined at least once every 6 months; however, where previous or subsequent test records show that the specific gravity has not varied by an amount which would make an error in the measurement greater than is consistent with accepted engineering practice, the specific gravity of the gas may be determined at longer intervals not to exceed 1 year.

   (2)  Rotary displacement meters shall be tested and calibrated at the factory in accordance with recognized and accepted practices and shall be correct to within 1.0% when passing gas at their rated capacities. A record of the test shall be made available to and retained by the utility for the life of the meter. At least once every 10 years’ a differential-rate test shall be made and the results checked against the original test recorded at the time of installation. At least every 5 years’ the meter shall be inspected to observe the condition of the meter bearings noise, vibration, and the like, and the level and condition of the oil in the reservoirs, except that those meters installed before January 1, 1990, shall be inspected every 2 years. An observed problem shall be promptly corrected. A record of the results of these 5 year tests or 2 year tests for the pre 1990 installed meters shall be maintained by the utility for 5 years. In lieu of a differential-rate test, a test method approved by the Commission may be used.

   (3)  Turbine meters shall be tested and calibrated at the factory in accordance with recognized and accepted practices and shall be correct to within 1.0% when passing gas at their rated capacities. A record of the test shall be made available to and retained by the utility for the life of the meter. At least once every 2 years, a spin test shall be made and the results checked against the minimum spin test time specified by the manufacturer for the size meter being tested. If the spin time is not up to standard value, corrective measures shall be taken. In lieu of a spin test, a test method approved by the Commission may be used.

 (b)  Standard test schedule for Class A, Class B and Class C Meters. Unless otherwise provided by this section, each public utility shall make and record tests of Class A, Class B and Class C meters on the following schedule:

 (c)  Extended test schedule for Class A, Class B or Class C meters. A public utility may depart from the requirements of subsection (b) for Class A, Class B or Class C meters in a testing year, and instead make and record tests using one of the test periods prescribed in paragraph (5), if the following requirements are met:

   (1)  At the end of the first immediately preceding year, not less than 98% of the meters of that class in service had been removed within whichever is the greater of 2 years plus the test period prescribed therefor in subsection (b), or the test year permitted for that class of meter for that year by paragraph (5); and, as to a meter of that class not so removed, the premises where it was located were visited and a written notice requesting an appointment for meter change was either left at the premises or posted to the mailing address of the customer as it appears in the public utility’s files. Meters removed under this paragraph shall be tested and included in the calculations under paragraph (2) unless a meter was permanently retired from service or damaged by factors other than normal age or wear such as tampering or damage beyond the control of the public utility.

   (2)  The slow meter ratios and fast meter ratios of the meter class for the second immediately preceding year and the third immediately preceding year fall below the maximum percentages prescribed in paragraph (5). Any conflict between the test periods prescribed in paragraph (5) shall be resolved by using the shortest applicable test period.

   (3)  On or before March 1 of each testing year, the public utility submits to the Commission a report showing both in absolute numbers and in percentages the facts prescribed in paragraphs (1) and (2).

   (4)  For each year in which a public utility uses the extended test schedule in this subsection, the public utility may not remove or test any meters of the same class using the statistical sampling program in subsection (d) or the variable interval program in subsection (e).

   (5)  Subject to the qualifications prescribed in paragraphs (1)—(4), a public utility may make and record tests of Class A, Class B or Class C meters on the following schedule:

 (d)  Statistical sampling for Class A, Class B or Class C meters. A public utility may depart from the requirements of subsection (b) for Class A, Class B or Class C meters, and instead make and record tests of Class A, Class B or Class C meters under a statistical sampling program, if the following requirements are met:

   (1)  Meters shall be divided into groups in accordance with ANSI Spec, B109.1 Part IV Sec. 4.3.2.1 or its successor. A detailed description of the composition of each group of meters, such as year set, manufacturer, case type and diaphragm material, shall be provided in the annual report to the Commission.

   (2)  Sufficient meters shall be tested annually to insure a 90% confidence level that the meter groups are performing within accuracy limits.

   (3)  For a group to remain in service, at least 80% of the meters in the sample test shall meet the accuracy limits of 98% average accuracy (2% slow) and 102% average accuracy (2% fast). If a group of meters does not meet the performance standards, corrective action shall be taken. The corrective action may consist of removing the entire group from service within 4 years or, if the group consists of one or more subgroups, implementing a selective meter removal program to improve the accuracy of the group to within acceptable limits. The selective removal program may be as follows:

     (i)   If test results indicate one or more subgroups do not meet the performance standards, the subgroup shall be identified and removed within 4 years.

     (ii)   Once identified as a group or subgroup not meeting the performance standards and during the removal process, that group or subgroup shall be removed from the sampling plan.

   (4)  The statistical sampling schedule shall be in accordance with the provisions of ANSI Spec. B109.1 Part IV Sec. 4.3.2.1 or its successor.

   (5)  A utility electing the statistical sampling program shall remain on that program for at least 4 years.

   (6)  For each year in which a public utility uses the statistical sampling approach in this subsection, the public utility may not remove or test any meters of the same class using the extended test schedules in subsection (c) or the variable interval program in subsection (e).

 (e)  Variable interval testing for Class A, Class B or Class C meters. A public utility may depart from the requirements of subsection (b) for Class A, Class B or Class C meters, and instead make and record tests of the Class A, Class B or Class C meters under a variable interval program, if the following requirements are met:

   (1)  Meters shall be divided into groups in accordance with ANSI B109.1 Part IV Sec. 4.3.2.2 or its successor. A detailed description of the composition of each group of meters, such as year set, manufacturer, case type and diaphragm material, shall be provided in the annual report to the Commission.

   (2)  The number of meters to be removed in any year will be determined from the test results of the second immediately preceding year’s incoming meters. Meters removed under this paragraph shall be tested and included in the calculations under paragraph (3) unless a meter was damaged by factors other than normal age or wear such as tampering or damage beyond the control of the utility.

   (3)  Except as provided in paragraphs (4) and (5), the ratio (r) of the number of meters in a test group to be removed to those in service in that test group shall be determined by the formula (r = .02 + .3d) where (d) is the ratio of meters which have an average accuracy of less than 98% or more than 102% as reported to the nearest 1/2%, to the total number of meters tested in the group during the second immediately preceding year.

   (4)  Meters removed in a test group in excess of the ratio (r) as described in paragraph (3) shall be credited towards the ratio (r) for a better performing test group.

   (5)  A utility may petition the Commission for an Accelerated Retirement Program (ARP) for a specific meter type that the utility may desire to purge from its system. Meters removed in an ARP in excess of the ratio (r) as described in paragraph (3) may be credited towards the ratio (r) for any other test group regardless of performance.

   (6)  A utility electing the variable interval plan shall remain on that plan for at least 4 years.

   (7)  For each year in which a public utility uses the variable interval approach in this subsection, the public utility may not remove or test any meters of the same class using the extended test schedules in subsection (c) or the statistical sampling program in subsection (d).

 (f) Meter test on request of customer. Meter tests, if requested by a customer, shall conform with all of the following:

   (1)  If a customer requests, in writing, a test of the accuracy of the meter through which gas service is supplied and the meter is not due for periodic test, the public utility shall notify the customer of the conditions under which the test will be made by the utility or by a referee. If the customer then requests the utility to proceed with the test and remits an amount equal to the scheduled cost of a referee test, the utility shall make the test promptly. If, when tested, the meter is found to be more than 2.0% fast or slow, the testing fee shall be promptly refunded to the customer.

   (2)  A customer or his representative may be present when the public utility conducts the test on the meter.

   (3)  A report giving the name of the customer requesting the test, the date of the request, the location of the premises where the meter had been installed, the type, make, size, and serial number of the meter, the date of removal, the date of the test, the result of the test and the amount of refund if the meter was found more than 2.0% fast, shall be supplied to the customer within 10 days after the completion of the test.

   (4)  The amount of the fee which may be charged by the public utility for testing meters upon the written request of a customer shall be determined by the designated rating of the manufacturer as follows. Displacement meters shall be subject to the following fee schedule:

     (i)   Meters having a rated capacity of 500 cubic feet per hour or less—$10.

     (ii)   Meters having a rated capacity of over 500 cubic feet per hour, and not more than 1,500 cubic feet per hour—$20.

     (iii)   Meters having a rated capacity of over 1,500 cubic feet per hour, orifice meters, and any meters not a displacement type—$30.

   (5)  The provisions of this section may not interfere with the practice of a public utility with reference to its regular tests of meters; except that, in the event of an application by a customer to the Commission for a referee test, the utility may not knowingly remove, interfere with or adjust the meter to be tested without the written consent of the customer and approval of the Commission.

 (g)  Installation test. Each gas meter shall be in good order and shall be correct at all test rates of flow to within 2.0% fast or slow before being installed. In the case of new meters or meters reconditioned by a manufacturer, the test results of the manufacturer can be accepted as the installation test if the utility has verified the manufacturer’s reported test results by testing a minimum of 10% or ten meters—whichever is greater—of each shipment of meters. However, in case of an emergency, a meter not meeting the requirements of this section may be installed temporarily. Each meter tested by the utility under this subsection shall also be tested for pressure as follows: every meter shall be subjected to a pressure test before being installed; the minimum test pressure shall be 1.5 times the maximum metering pressure that the meter will be exposed to during its time in service.

 (h)  Determining accuracy of small meters. For the purpose of determining compliance with subsection (e), the registration of a displacement meter shall be determined by one test at a rate of flow of approximately 1/5 of its rated capacity (check flow) and by a second test at approximately the full rated capacity of the meter. The capacity of the meter for test purposes shall be the capacity at 1/2 inch differential pressure. Prior to installation of a meter, the tests at the two rates of flow shall agree within 2.0%. In determining compliance and for the purpose of computing refunds, the check flow test may be considered as the accuracy of the meter. A utility may, at its option applicable to all of its small meters, consider the accuracy of a meter to be the algebraic mean of two errors found, one at check flow and one at capacity flow. If unusual conditions indicate that an unusual test rate of flow should be used, the test record shall show the rate used.

 (i)  Meter prover. Tests to determine the accuracy of a gas service meter used to measure gas at standard distribution pressure shall be made with a bell type meter prover unless, because of unusual capacity or construction of a meter, the method of test is considered impracticable, under which condition the test shall be made by some other method approved by the Commission.

 (j)  Testing large displacement meters. The testing of large displacement meters shall conform with the following:

   (1)  Tests on displacement meters shall be made with approved testing apparatus. The meters should be tested in their permanent locations on the premises of the customer if practicable. If critical flow provers or low pressure flow provers are used for making such tests, the accuracy should be determined at three or more rates of flow, ranging from 20% of the rated capacity at 1/2 inch differential pressure up to flow at the maximum operating rate.

   (2)  If testing with the critical flow prover, the meter shall be operated at a static pressure which approximates the average operating static pressure. If similar tests are made with a low pressure flow prover, average operating pressure should be maintained on the meter under test and the prover operated at a range of low pressures required for a prover. In installations where meters operating on pressures higher than standard service pressure are limited in their maximum operating dial rate so as to keep the differential pressure equal to or less than 2 inches water column, low pressure flow prover tests may be run with low pressure on the meter. In the flow tests by either method, the maximum dial rate shall insure that tests being run at meter differential pressures are equivalent to normal operating meter differential pressures in all cases. If it is not practicable to test rotary displacement meters with a flow prover, they shall be inspected and tested by approved methods to determine whether they conform reasonably to the original factory test data.

   (3)  An instrument or auxiliary device used in conjunction with a gas meter to correct the metered volume for pressure or temperature shall be adjusted to an accuracy level to assure that the combined percentage of error of the instrument or auxiliary device, or both, and the associated meter does not exceed plus or minus 2.0% error. This shall be verified by test prior to installation and at the time of any subsequent meter tests. In tests conducted after installation the meter and its associated auxiliary device may not be tested more than 30 days apart. Each instrument and auxiliary device shall be verified for accuracy or calibrated at least annually to verify the performance. A record of the most recent verifications shall be kept for each instrument and device.

 (k)  Testing orifice meters. Tests on orifice meters shall be made with approved testing apparatus and in their permanent locations on the premises of the customer. The accuracy of the differential pressure registration shall be determined on a rising and falling pressure throughout the entire operating pressure range of the gauge. The accuracy of the static pressure registration shall be determined at the operating pressure.

 (l)  Determining accuracy of orifice and large displacement meters. In determining the accuracy of orifice and large displacement meters, the average of the errors determined at the various rates of flow at which the meter was tested shall be taken and shall be considered as its accuracy in determining compliance with subsection (e) and for the purpose of computing refunds; however, if the rates of flow at which the meter has been registering in service may be definitely established, the weighted average error shall be determined and used.

 (m)  Test record data. Whenever a meter is tested, the original test record shall include information necessary for identifying the meter, the reason for making the test, the date and location of the test, the name of the person making the test, the reading of the meter upon removal from service, the result of the test, and data taken at the time of the test. The record shall be in complete form so as to permit the convenient checking of the methods employed and the calculations made.

 (n)  Meter records. A record shall be maintained for each meter owned or used by a public utility. It shall indicate whether acquired new or otherwise, the date of purchase, identification, and the results of the most recent test and shall contain any additional test records required to be kept by other provisions of this title relating to gas meters. This record may not be destroyed without Commission authorization.

 (o)  Capping meters. Incoming meters shall be capped when removed from service and awaiting test. Meters which have been tested or are reading for installation shall be capped and remain capped until installed.

   The provisions of this §  59.21 issued and amended under Public Utility Code,66 Pa.C.S. § §  501, 1301, 1304, 1501, 1502, 1504, 1507 and 1508.

   The provisions of this §  59.21 amended through May 30, 1986, effective May 31, 1986, 16 Pa.B. 1901; amended July 3, 1997, effective August 4, 1997, 27 Pa.B. 3215; amended July 2, 1998, effective August 3, 1998, 28 Pa.B. 3050. Immediately preceding text appears at serial pages (232255) to (232263).

 (a)  Fast meters. If, upon test of a meter, it is found to have an average error of more than 2.0% fast, the public utility shall refund to or credit the customer for the overcharge, based upon what the meter would have registered had it not been fast or slow for a period equal to 1/2 the time elapsed since the last previous test, but not to exceed 12 months or 1/2 the period of occupancy of the premises by the customer, whichever is less. If the period of registration error may be definitely fixed, the overcharge shall be computed for the period. If the meter has not been tested under §  59.21 (relating to meter tests), the period for which it has been in service beyond the regular test period shall be included in computing the refund.

 (b)  Slow meters. If, upon test of a gas meter it is found to have an average error of more than 2.0% slow, the public utility may render a bill for the gas consumed but not covered by bills previously rendered, for a period equal to 1/2 of the time elapsed since the last previous test, but not to exceed 3 months. If the period of registration error may be definitely fixed, the charge may be computed for the period.

 (c)  Nonregistering meters. If a meter has failed to register for a period, the public utility may compute the gas used by taking the average of the gas used for the nearest meter-reading period preceding and the meter-reading period immediately following the date when the meter was found to be not registering, which amount shall be assumed to be the amount of gas used by the customer during the billing period in which the meter was found not to have registered. Exceptions will be made only if the facts clearly show that the stated method does not give the correct consumption for the period.

 (a)  Access to meters. Each public utility shall at reasonable times have access to meters, service connections and other property owned by it on the premises of customers, for purposes of maintenance, operation and meter reading. Neglect or refusal on the part of customers to provide reasonable access to their premises for the purposes shall constitute sufficient cause for discontinuance of service.

 (a)  A public utility may initially decline to serve an applicant if, in the judgment of the utility, any of the following conditions are present:

   (1)  The applicant has not complied with Commonwealth and municipal regulations governing gas service, and with the rules and regulations of the utility.

   (2)  The installation of piping or gas equipment of the applicant is hazardous or improper.

   (3)  The service requested by the applicant is unreasonable and improper under the circumstances.

 (b)  A public utility may decline to serve an existing customer if, in the judgment of the utility, a hazardous condition exists regarding the piping or gas equipment of the customer.

   The provisions of this §  59.26 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 1501, 1504, 1507 and 1508.

 (a)  Displacement meters. Each public utility shall adopt standard methods for installing meters.

 (b)  Orifice meters. All orifice meter settings shall be constructed and maintained in accordance with accepted good practice, which is best indicated by the American Gas Association; 1515 Wilson Boulevard; Arlington, Virginia 22209: Orifice Metering of Natural Gas, ‘‘Gas Measurement Committee Report No. 3,’’ ANSI/API 2530 1978.

 (c)  Service connection. When connecting the premises of the customer with public utility distribution mains, the public utility shall furnish, install and maintain the service line or connection according to the rules and regulations of its filed tariff.

   The provisions of this §  59.28 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 1301, 1304, 1501, 1502 and 1507.

 (a)  Maximum pressure. The maximum pressure specified for a low pressure system may not be greater than a pressure which will not cause the unsafe operation of connected and properly adjusted gas utilization equipment or 14 inches of water column (8.1 ounces), whichever is less, at the outlet of the service meter of a low pressure customer.

 (b)  Minimum pressure. The minimum pressure at the outlet of a service meter of a low pressure customer may not be less than a pressure which will not cause the unsafe or inadequate operation of a connected and properly adjusted gas utilization equipment or 2 inches of water column (1.2 ounces), whichever is greater, unless due to insufficient capacity of the service line owned by the customer.

 (c)  Changing pressure. A public utility may change the distribution pressure for any system, but if a change is made, all appliances of a customer located within the system shall, if necessary, be readjusted by and at the expense of the utility.

 (d)  Pressure gauges. A public utility shall maintain and operate on the outlet side of the system regulator station, at least one recording gas pressure gauge of suitable range. If more than one regulator station is used to serve a single pressure system, recording pressure gauges need not be installed for each regulator station. A sufficient number of recording pressure gauges shall be installed and operated in each distribution system to furnish a continuous record of the pressure prevailing in all parts of the system.

   The provisions of this §  59.29 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 1501, 1504, 1507 and 1508.

   The provisions of this §  59.29 amended May 30, 1986, effective May 31, 1986, 16 Pa.B. 1901; amended July 2, 1998, effective August 3, 1998, 28 Pa.B. 3050. Immediately preceding text appears at serial pages (211171) to (211172).

 (a)  Testing apparatus. The accuracy of testing apparatus, as well as the method of making heating-value tests, shall be subject to the approval of the Commission.

 (b)  Tests. Each public utility shall make or obtain the determinations as may be necessary to ascertain the heating value of the gas introduced into its distribution system and shall maintain an average heating value not less than the minimum authorized. If compression, processing or other factors tend to affect the heat content of all or any portion of its gas, determinations of heating value shall be made of gas drawn from different parts of the distribution system at points remote from the point where the gas enters the distribution system, with the frequency and in the manner as may be necessary to assure compliance with this section.

 (c)  Records of tests. Each public utility shall adopt a standard printed form for recording the results of heating value tests. Each determination of heating value shall be recorded originally upon the form adopted for that purpose. If heating value is determined by an approved type of recording calorimeter, the charts removed from a calorimeter shall be sufficient to comply with the requirements of this section. If manufactured or mixed gas is served, the average heating value determined by these tests shall be recorded.

 (d)  Heating value. The heating value of gas shall be as follows:

   (1)  Natural gas. If a public utility supplies natural gas, its heating value may not fall below 950 Btu total heating value per cubic foot, under standard conditions of temperature and pressure.

   (2)  Manufactured or mixed gas. Manufactured or mixed gas shall conform with all of the following:

     (i)   If a public utility supplies manufactured or mixed gas, its heating value shall have a monthly average of not less than 520 Btu total heating value per cubic foot under standard conditions of temperature and pressure. The minimum heating value of manufactured gas shall never fall below 500 Btu.

     (ii)   To obtain the heating value of gas, the results of the tests of heating value made under standard practice on each day during the calendar month shall be averaged, and the average of the daily averages shall be taken as the monthly average.

     (iii)   Each public utility serving manufactured or mixed gas shall provide and maintain a calorimeter with necessary accessories of an approved type for the regular determination of the heating value of the gas sold, unless other provision is made with the approval of the Commission.

     (iv)   The calorimeter required for measuring manufactured or mixed gas shall be installed in a laboratory or other building so located as to insure that thoroughly mixed, stabilized and representative samples of the gas delivered to customers are used for the tests.

     (v)   Each public utility serving manufactured or mixed gas shall determine the heating value of the gas distributed to its customers daily or more frequently if necessary, or if required by the Commission.

 (e)  Purity of gas. The purity of gas distributed in this Commonwealth shall conform with the following:

   (1)  Gas shall be substantially free from dangerous or objectionable quantities of impurities such as hydrogen sulphide, nitrogen or other combustible or noncombustible constituents which, if the gas is completely burned, yield noxious or toxic products of combustion.

   (2)  Hydrogen sulphide in the gas shall be considered negligible if a strip of white filter paper, moistened with a solution containing 5.0% by weight of lead acetate, is not distinctly darker than a second paper freshly moistened with the same solution, after the first paper has been exposed for one minute in an apparatus of approved form, through which the gas is flowing at the rate of approximately 5 cubic feet per hour, the gas not impinging directly from the jet upon the test paper.

 (a)  Conditions of service. Service to applicants directly from production or transmission lines which are not part of the distribution system from which customers are normally supplied shall be furnished under conditions stated in the tariff rules and regulations of the utility.

 (b)  Excess pressure protection. If the pressure from lines governed by this section is reduced to standard service pressure for use by the customer, the installation shall be provided with adequate over-pressure protection to prevent the pressure from exceeding two pounds per square inch in the event of regulator failure.

 (c)  Cost of equipment. The utility may require a customer served directly from a line governed by this section to provide and install the regulator and excess pressure protective device necessary to render service, or the utility may provide such equipment and make a reasonable charge for the equipment and its installation.

 (d)  Location of equipment. If a customer is served directly from a line governed by this section, the regulator and meter shall be located as closely as possible to the point where the line is tapped.

 (a)  Responsibility. Each public utility shall at all times use every reasonable effort to properly warn and protect the public from danger, and shall exercise reasonable care to reduce the hazards to which employes, customers and others may be subjected to reason of its equipment and facilities.

 (b)  Safety code. The minimum safety standards for all gas transmission and distribution facilities in this Commonwealth shall be those issued under the pipeline safety laws as found in 49 U.S.C.A. § §  60101—60503 and as implemented at 49 CFR Parts 191—193 and 199, including all subsequent amendments thereto future Federal amendments to 49 CFR Parts 191—193 and 199, as amended or modified by the Federal government, shall have the effect of amending or modifying the Commission’s regulations with regard to the minimum safety standards for all gas transmission and distribution facilities. The amendment or modification shall take effect 60 days after the effective date of the Federal amendment or modification, unless the Commission publishes a notice in the Pennsylvania Bulletin stating that the amendment or modification may not take effect.

 (c)  Enforcement. Each public utility shall be subject to inspections as may be necessary to assure compliance with this section. The facilities, books and records of each public utility shall be accessible to the Commission and its staff for the inspections. Each public utility shall provide the Commission or its staff the reports, supplemental data and information as it shall from time to time request in the administration and enforcement of this section.

 (d)  Records. Each public utility shall keep adequate records as required for compliance with the code in subsection (b). The records shall be accessible to the Commission and its staff.

   The provisions of this §  59.33 issued and amended under the Public Utility Code, 66 Pa.C.S. § §  331, 501, 1501, 1504, 1507 and 1508.

   The provisions of this §  59.33 amended through May 30, 1986, effective May 31, 1986, 16 Pa.B. 1901; amended July 2, 1998, effective August 3, 1998, 28 Pa.B. 3050; amended June 23, 2006, effective June 24, 2006, 36 Pa.B. 3092. Immediately preceding text appears at serial pages (304705) to (304706).

   (Editor’s Note: Publication of notice ratifying the amendments to 49 CFR Parts 191, 192, 193 and 199 appeared at 27 Pa.B. 851 (February 15, 1997), 33 Pa.B. 5486 (November 1, 2003) and 34 Pa.B. 3655 (July 10, 2004). See serial pages (800645) to (800646)).

 (a)  Plan. A public utility shall establish and execute a plan by which it will periodically survey each customer-owned service line for leakage. The plan shall conform with or exceed the standards estalbished in 49 CFR 192.723 (relating to distributuion systems; leakages and procedures) as of May 1, 1986 and subsequent amendments thereto which have been ratified by the Commission under §  59.33 (relating to safety). The public utility shall file with the Commission a copy of the plan required by this subsection including statements of the type of survey it will use and of the frequency of the survey. As used in this section, the term ‘‘customer-owned service line’’ includes that piping serving a residential or commercial customer which is between the main, pipeline or other source of supply and whichever is the more remote of either the meter set assembly, or the wall of the residence or commercial building if the customer owns part of the piping.

 (b)  Access to customer premises. If the leakage survey prescribed by subsection (a) requires access to the premises of a customer and the customer refuses access, or if the public utility requires a customer to inform it of the location of a service line and he fails to provide the information, the public utility may shut off gas service until access is permitted or the information is provided. If subsection (a) requires a leakage survey to a meter set assembly inside the wall of a residence or commercial building, and the public utility cannot gain access to the building because of absence of the occupants, the public utility shall leave a notice at the premises, instructing the customer to designate to the public utility a day and time during normal working hours when access may be had. The public utility may defer the leakage survey to the day and time so designated.

 (c)  Procedure after survey. Upon completion of a survey of a customer-owned service line, the public utility shall make a record showing the date and method of the survey, and the result found. If the result shows that a leak exists in the service line, the public utility shall require the customer to repair or renew the line, and may shut off gas service until repair or renewal has been effected. The public utility shall retain the record of the two most recent surveys made under this section.

 A significant increase in the normal operating pressure of a distribution or transmission pipeline shall be made in accordance with 49 CFR Part 192, Subpart K (relating to uprating) as of May 1, 1986, and subsequent amendments thereto which have been ratified by the Commission under §  59.33 (relating to safety). A leak survey of mains and services shall be made prior to increasing the pressure initially and also following each incremental increase in pressure. Structures abutting or adjacent to the gas mains shall be inspected to confirm the utility’s records as to the presence or absence of a gas service line on each property.

   The provisions of this §  59.35 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 1501, 1504, 1507 and 1508.

 A public utility shall have a plan for abandoning inactive service lines under 49 CFR 192.727 (relating to abandonment or inactivation of facilities) as of May 1, 1986 and subsequent amendments thereto which have been ratified by the Commission under §  59.33 (relating to safety), and shall have a copy of its plan available for inspection. The plan shall require the following:

 (1)  Service lines which are not constructed of noncorrosive material or part of a cathodic protection system which have been inactive for 3 months and for which there is no prospect of reuse shall be scheduled for abandonment under 49 CFR 192.727 as of May 1, 1986 and subsequent amendments thereto which have been ratified by the Commission under §  59.33, as soon as practicable but not later than 6 months after it has been determined there is no prospect for reuse.

 (2)  Service lines which have been inactive for 3 months and for which there is a reasonable prospect of future use shall be shut off under 49 CFR 192.727(d) as of May 1, 1986 and subsequent amendments thereto which have been ratified by the Commission under §  59.33. A review of the status of inactive lines shall be made annually, at periods not exceeding 15 months. Lines which no longer qualify for retention shall be abandoned under paragraph (1).

 (3)  Inactive service lines shall be leakage surveyed periodically under 49 CFR 192.723 (relating to distribution systems; leakage surveys and procedures) as of May 1, 1986 and subsequent amendments thereto which have been ratified by the Commission under §  59.33. An inactive service line found to be leaking shall be abandoned immediately if hazardous. If the leak is not hazardous, the line shall be abandoned within 3 months or repaired within this time period if the line is constructed of noncorrosive material or part of a cathodic protection system.

 (4)  Unrecorded inactive service lines discovered in the course of leakage surveillance, construction, maintenance or inspection of facilities shall be abandoned as follows: If leaking, abandon immediately; if not leaking, abandon as soon as practicable but not more than 10 days after discovery.

 (5)  If a building is to be demolished or if there will be a major excavation of property on which there is an active or inactive service line, and if there is no reasonable prospect of future use, the service line shall be abandoned at the main under paragraph (1). If there is a reasonable prospect of future use, the service line may be abandoned at the curb or property like and its status shall be reviewed annually, at periods not exceeding 15 months, under paragraph (2). The service line shall be disconnected either at the main or property line prior to demolition or excavation.

   A public utility shall notify the Commission of proposed major construction, reconstruction or maintenance of plant at least 30 days prior to the commencement of work. Major construction, reconstruction or maintenance is defined for this reporting as a single project involving an expenditure in excess of $300,000 or 10% of the cost of the utility’s plant in service, whichever is less, production well drilling to be excluded. This notification of proposed construction shall include the following:

   (1)  Description and location (city, township, county) of proposed work.

   (2)  Type of facility (distribution main, transmission pipeline, compressor station, and the like).

   (3)  Estimated starting date.

   (4)  Estimated completion date.

   (5)  Design pressure.

   (6)  Estimated cost.

   (7)  Name and address of reporting gas company.

   (8)  Name, address and telephone number of person to be contacted regarding the project.

   (9)  Notification to the Commission of the completion date.

   The provisions of this §  59.38 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 1501, 1504, 1507 and 1508.

   The provisions of this §  59.38 amended May 30, 1986 effective May 31, 1986, 16 Pa.B. 1901; amended July 2, 1998, effective August 3, 1998, 28 Pa.B. 3050. Immediately preceding text appears at serial page (211177).

ACCOUNTS AND RECORDS

§ 59.41. Classification of gas public utilities.

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

   (1)  Major. Public utilities having annual gas operating revenues of $1 million or more.

   (2)  Nonmajor. Public utilities having annual gas operating revenues of less than $1 million.

   The provisions of this §  59.41 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 1501, 1504, 1507 and 1508.

 (a)  Each major gas public utility shall keep its accounts in conformity with the ‘‘Uniform System of Accounts Prescribed for Natural Gas Companies (Major)’’ by the Federal Energy Regulatory Commission (18 CFR Part 201).

 (b)  Each nonmajor gas public utility shall keep its accounts in conformity with the ‘‘Uniform System of Accounts Prescribed for Natural Gas Companies (Non-Major)’’ by the Federal Energy Regulatory Commission (19 CFR Part 201).

 (c)  A gas public utility with annual gas operating revenue of less than $25,000 shall keep the accounts as will be adequately informative for reasonable and foreseeable regulatory purposes.

 (d)  This section applies to manufactured gas public utilities.

   The provisions of this §  59.42 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 1501, 1504, 1507 and 1508.

   The provisions of this §  59.42 amended July 2, 1998, effective August 3, 1998, 28 Pa.B. 3050. Immediately preceding text appears at serial page (211178).

 (a)  All revenues from and costs and expenses pertaining to merchandising, jobbing and contract work shall be recorded appropriately in Accounts 914 and 915, in the case of Class A, Class B and Class C companies and appropriately in Accounts 780 and 781 in the case of Class D companies in the unified system of accounts prescribed in §  59.42 (relating to systems of accounts).

 Each gas 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 §  59.45 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 504—506, 1301 and 1501.

 (a)  A utility whose annual operating revenues are $25,000 or more but less than $100,000 may not be required to reclassify the cost of plant installed prior to January 1, 1961, to an original cost basis until the time as its annual operating revenues reach $100,000 or more.

 (b)  When the annual operating revenues of a public utility become $100,000 or more, the utility shall be subject to Class C accounting requirements. The public utility shall within 2 years submit the following detailed statements relative to its plant account reclassification at original cost. The statements shall be sworn to or affirmed by the officer of the company responsible for their preparation, as follows:

   (1)  Statement A. Statement A shall show in outline form the origin and development of the utility, including a description of each consolidation and merger to which the utility or a predecessor was a party, and each acquisition of a gas operating unit or system by the utility or a predecessor. If any transaction relating to such property involved utility property other than the gas plant, that fact shall be stated.

   (2)  Statement B. Statement B shall show the chartered gas territory of the utility, giving the development of that territory according to each consolidation and merger or gas plant acquisition to which the utility or a predecessor was a party.

   (3)  Statement C. Statement C shall show a summary of gross debits and credits to Accounts 101, 102, 103, 104, 105, 106, 107 and 114, gas plant, from the date of origin of the gas plant of the utility to the effective date of such system of accounts as prescribed by §  59.42 (relating to systems of accounts), setting forth all of the following:

     (i)   Plant acquired by merger and consolidation.

     (ii)   Plant constructed by the utility.

     (iii)   Plant acquired by purchase.

     (iv)   Total.

     (v)   Retirements of plant which cannot be classified by the specific divisions of subparagraphs (i)—(iii).

     (vi)   Balance at effective date of the system of accounts.

   (4)  Statement D. Statement D shall show a summary analysis of the accumulated provisions for the depreciation, amortization and depletion of the gas plant, as established by the utility and its predecessors, from the date of origin of the gas plant of the utility to the effective date of the system of accounts as prescribed by §  59.42, showing all of the following:

     (i)   Credits arising from charges to operating expenses.

     (ii)   Salvage and other credits detailed by nature of transaction.

     (iii)   Gross debits for plant retired.

     (iv)   Cost of removal, and other debits detailed by nature of transaction.

     (v)   Balance at effective date of the system of accounts.

   (5)  Statement E. Statement E shall show contributions received by the utility and its predecessors, from customers or others, in the aid of construction of a gas plant, setting forth all of the following:

     (i)   The gross amount of contributions received from the date of origin of gas service to the effective date of such system of accounts as prescribed by §  59.42.

     (ii)   The amount of the contributions returned or retired as of the effective date of the system of accounts.

     (iii)   The difference between subparagraphs (i) and (ii).

     (iv)   The amount reflected in Account 271, ‘‘Contributions in aid of construction,’’ at the effective date of the system of accounts.

     (v)   A reconciliation of the difference between subparagraphs (iii) and (iv).

   (6)  Statement F. Statement F shall conform with all of the following:

     (i)   Statement F shall show, for each acquisition through consolidation and merger or purchase of a gas operating unit or system by the utility or a predecessor, all of the following:

       (A)   A description of the property acquired.

       (B)   The names of parties to the transaction and whether the parties were affiliated.

       (C)   The date the transaction was consummated.

       (D)   The original cost, estimated if not known.

       (E)   The value of the plant, as reflected on books of merger constituent or vendor.

       (F)   The cost of the plant to the acquirer, and the manner and method of determination of such cost.

       (G)   The amount recorded on the books of the acquirer with respect to the plant acquired.

       (H)   The amount accumulated provisions for depreciation applicable to the plant acquired, as reflected on books of merger constituent or vendor.

       (I)   An adjustment of amortization or depletion of the acquirer in respect to the plant acquired and the basis thereof.

       (J)   A summary of the appraisal, if any, prepared for the plant acquired at the date of acquisition, showing the elements of value included therein, by whom prepared, and the date. With respect to each acquisition, there shall be shown the difference between original cost and the amount recorded on the books; a summary of all transactions affecting the difference between the date of acquisition and the effective date of such system of accounts prescribed by §  59.42; and the resultant amount on the latter

date. The amount to be included in Account 114, ‘‘Gas plant acquisition adjustments,’’ shall be subdivided to show the amounts applicable to plant in service, plant leased to others, and plant held for future use. If practicable, the amount shall be classified according to its nature, that is, structural value, going value, and the like.

     (ii)   If estimates are used in arriving at original cost or the amount to be included in Account 114 of the uniform system of accounts prescribed by §  59.42, a full disclosure of the method or methods used in preparing the estimates, with the underlying facts, shall be given. The method or methods of determining the original cost of the gas plant acquired as operating units or systems shall be described in sufficient particularity to permit a clear understanding of the investigations which were made for that purpose. The amount claimed as the original cost of acquired property shall be supported by separate statements for each acquisition by the respondent and by each successive predecessor (prepared from the books and records of each predecessor company) showing a summary of gross debits and credits to the gas plant, classified by balance sheet subaccounts, from the date of origin of the gas plant of the predecessor to the date of dissolution or the effective date of sale or other transfer of the gas plant, setting forth all of the following:

       (A)   Plant acquired by merger and consolidation.

       (B)   Plant constructed by such predecessor.

       (C)   Plant acquired by purchase.

       (D)   Total.

       (E)   Retirements of plant which cannot be classified by the specific divisions in subparagraphs (i)—(iii).

       (F)   Balance at date of dissolution or effective date of sale or other transfer of the gas plant.

     (iii)   There shall also be shown a summary analysis of the related accumulated provisions for depreciation, amortization, and depletion of the gas plant as established by each predecessor, setting forth all of the following:

       (A)   Credits arising from charges to operating expenses.

       (B)   Salvage and other credits detailed by nature of transaction.

       (C)   Gross debits for plant retired.

       (D)   Costs of removal, and other debits detailed by nature of transaction.

   (9)  Statement G. Statement G shall show the amounts arrived at by appraisals recorded prior to the effective date of the system of accounts prescribed by §  59.42 in lieu of cost to the reporting company. This statement should give the full journal entry at the time the appraisal was originally recorded, and if the entry had the effect of appreciating or writing up the gas plant account, the amount of the appreciation or write up should be traced, by proper description and explanation of the changes from the date recorded to the effective date of such system of accounts.

   (10)  Statement H. Statement H shall show gas plant per books immediately prior to reclassification in accordance with the system of accounts prescribed by §  59.42 including, under a descriptive heading, an unclassified amounts applicable jointly to the gas department and other departments of the utility.

   (11)  Statement I. Statement I shall show a summary of adjustments necessary to record, as of the effective date of the system of accounts prescribed by §  59.42, Accounts 101, 102, 103, 104, 105, 106, 107 and 114, gas plant, and Account 116, ‘‘Other Gas Plant Adjustments.’’

   (12)  Statement J. Statement J shall show gas plant balance sheet Accounts 101, 102, 103, 104, 105, 106, 107 and 114 as of the effective date of the system of accounts prescribed by §  59.42 classified according to detailed accounts, and showing also the amount includible in Account 116, ‘‘Other Gas Plant Adjustments.’’

   (13)  Statement K. Statement K shall show a comparative balance sheet, as of the effective date of the system of accounts prescribed by §  59.42 setting forth the accounts and amounts appearing in the books before the adjusting entries have been made and after the entries have been made.

 (a)  Each public utility having annual gas operating revenue of $100,000 or more shall maintain a continuing property record of its gas plant the cost of which is recorded in Accounts 101, 102, 103, 104 and 105 of the uniform accounting system prescribed by §  59.42 (relating to systems of accounts).

 (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 within 2 years after the effective date of its change of revenue classification for approval. Thereafter, a proposed major changes in the plan shall be submitted to the Commission for approval.

 (c)  Continuing property records shall contain detailed description and classification of property record units which meet the following objectives:

   (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 those records, shall include information as to the kind, character, size, quantity, location, year of placement and retirement, percentage of ownership, and original cost of gas 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 certain reports, and invoke penalties for failure to file the 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 with the Commission annual financial reports by April 30 immediately following the reporting year, for reports based upon the calendar year, and by July 31 immediately following the reporting year, 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 paragraph (1), 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 §  59.48 amended under Public Utility Code,66 Pa.C.S. § §  501 and 504.

   The provisions of this §  59.48 amended May 6, 1988, effective May 7, 1988, 18 Pa.B. 2106. Immediately preceding text appears at serial page (107928).

   This section cited in 52 Pa. Code §  101.2 (relating to definitions); and 52 Pa. Code §  101.4 (relating to reporting requirements).

SALES PROMOTION PRACTICES

§ 59.51. [Reserved].

   The provisions of this §  59.51 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 (246435) to (246436).

REPORTING AND CURTAILMENT OF SERVICE

   The provisions of these § §  59.61—59.67 issued under Public Utility Code,66 Pa.C.S. § §  501, 1501 and 1504, unless otherwise noted.

   The provisions of this §  59.61 adopted June 17, 1977, effective June 18, 1977, 7 Pa.B. 1641; amended June 17, 1977, effective June 18, 1977, 7 Pa.B. 2138; reserved March 22, 1996, effective March 23, 1996, 26 Pa.B. 1265. Immediately preceding text appears at serial pages (196683) to (196684).

   The provisions of this §  59.62 amended through July 1, 1983, effective July 2, 1983, 13 Pa.B. 2062; amended April 29, 1988, effective April 30, 1988, 18 Pa.B. 2028; amended March 22, 1996, effective March 23, 1996, 26 Pa.B. 1265; reserved amended July 2, 1998, effective August 3, 1998, 28 Pa.B. 3050. Immediately preceding text appears at serial pages (213706) and (211185) to (211186).

   Commission decision refusing exemption under 52 Pa. Code §  59.62(h)(4), because conversion from gas to electricity would not be unduly burdensome, was supported by substantial evidence where commission calculations indicated equal or slightly lower cost over five-year period. John Sheldrake, Inc. v. Pennsylvania Public Utility Commission, 494 A.2d 1171 (Pa. Cmwlth. 1985).

   Ban on sale of natural gas for use in commercial outdoor lights, 52 Pa. Code §  59.62(h) does not violate due process or equal protection clauses since it serves purpose of curtailing use of natural gas, aiding in conservation of a finite natural resource. John Sheldrake, Inc. v. Pennsylvania Public Utility Commission, 494 A.2d 1171 (Pa. Cmwlth. 1985).

   Voluntary unincorporated association of 30 residents, including Chatham College, owning property along street, is considered a residential customer, thereby entitled to exemption from the ban on outside natural gas lighting under subsection (h). Woodland Road Association v. Pennsylvania Public Utility Commission, 487 A.2d 1030 (Pa. Cmwlth. 1985).

 As part of its officially filed tariff, each jurisdictional gas utility shall have on file with the Commission natural gas emergency plans. The plans shall be under Commission requirements § §  59.71—59.75 (relating to gas emergency plans).

   The provisions of this §  59.63 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 2203(12) and 2208.

 (a)  Each major jurisdictional utility, as defined in §  59.61 (Reserved), shall inform the Commission, in writing, of any curtailment, breach of performance, suspension of performance or nonperformance by a gas supplier, transportation utility or major shipper (defined as any shipper utilizing transportation tariffs whose monthly demand is in excess of 5% of the jurisdictional utility’s monthly throughput in any given month) within 48 hours after the action becomes known to the jurisdictional utility. Notice to the Commission shall include a statement as to the estimated effect on the utility and its customers, including any resulting curtailments, penalties or additional costs.

   (b) Each major jurisdictional utility, as defined in §  59.61, shall contemporaneously notify its customers and the Commission whenever curtailments are instituted or changed. The notice shall be provided as soon as practicable.

   The provisions of this §  59.64 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 504, 1301, 1304, 1307, 1317 and 1318.

   The provisions of this §  59.67 amended November 16, 1979, effective November 17, 1979, 9 Pa.B. 3799; reserved March 22, 1996, effective March 23, 1996, 26 Pa.B. 1265. Immediately preceding text appears at serial pages (196688) to (196689), (107937) to (107940) and (116311).

GAS EMERGENCY PLANS

§ 59.71. Definitions.

 The following words and terms, when used in this section and in § §  59.72—59.75, have the following meanings, unless the text clearly indicates otherwise:

   Alternate fuel—Any fuel other than natural gas.

   Alternate fuel capability—The installed and operable ability to use any fuel other than natural gas on a time sensitive basis.

   Commercial use—Gas usage by customers engaged primarily in the sale of goods and services including consumption by office buildings, institutions and government agencies.

   Essential human needs use—Gas usage in any building where persons normally dwell including residences, apartment houses, dormitories, hotels, hospitals and nursing homes.

   Firm service—Natural gas service offered to consumers under tariffs or contracts that anticipate no interruption.

   Industrial use—Gas usage by customers engaged primarily in a process which creates or changes raw or unfinished materials into another form or product including the generation of electric power.

   Interruptible service—Natural gas services that can be temporarily discontinued under terms and conditions specified by tariff or contract.

   NGDC—Natural gas distribution company.

   NGS—Natural gas supplier.

   Plant protection use—Minimum usage of natural gas required to prevent physical harm to an industrial or commercial consumer’s facility, or danger to personnel at the facility, when the protection cannot be afforded through the use of an alternate fuel. Plant protection use includes usage necessary for the protection of the material in process as would otherwise be destroyed, but does not include deliveries required to maintain production.

   Residential use—Gas usage in a residential dwelling or unit for space heating, air conditioning, cooking, water heating or other domestic purpose.

   The provisions of this §  59.71 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 2203(15) and 2208.

   The provisions of this §  59.71 adopted December 14, 2001, effective December 15, 2001, 31 Pa.B. 6800.

 (a)  By March 15, 2002, each NGDC shall file with the Commission a natural gas emergency plan reflecting its unique operational characteristics and design criteria. Each plan shall contain simplified and understandable rules and regulations so that all of the NGDC’s customers and all NGSs licensed to provide services to their customers can have a responsive action plan in place to protect themselves and their property in the event of a crisis. NGDCs shall file revisions to their plans when and as appropriate, or as directed by the Commission.

 (b)  As part of their emergency planning, NGDCs shall attempt to make every reasonable effort to make contractual or informal arrangements with their transportation customers, sales customers and others to obtain supplies or, as an alternative, to implement usage reductions, so that resorting to firm service reductions under §  59.73 (relating to emergency action) can be avoided, or the severity of supply or capacity disruption can be mitigated. The purpose of these arrangements is to provide a means to minimize the potential of supply shortfalls that threaten public health and safety, and not to make up for inadequate performance by individual parties.

 (c)  Each natural gas emergency plan shall include provisions addressing:

   (1)  Emergency load shedding.

   (2)  Voluntary usage reductions, for example, reducing space or water heating temperatures to levels specified by the NGDC.

   (3)  Mandatory usage reductions for certain customers consistent with §  59.73(c).

   (4)  Issuance of periodic reports to the media concerning the existing natural gas emergency.

   (5)  Notice to affected customers and NGSs of the expected initiation of emergency actions under §  59.73.

   (6)  Customer and NGS delivery requirements that apply during the term of emergency action under §  59.73, regardless of customer-specific usage reductions that arise or may arise from end-use curtailments.

   (7)  A procedure for focusing emergency measures to confined geographic or operational portions, segments or zones of the NGDC system where a natural gas emergency exists.

   (8)  Procedures for establishing communications with electric system control area operators, if the NGDC provides gas service to electric generation stations.

 (d)  Each natural gas emergency plan shall specify the procedures the NGDC shall use to provide notices to affected customers, their NGSs and NGDCs. After the NGDC determines the appropriate response, the NGDC shall issue notices to affected customers, their NGSs and NGDCs as soon as reasonably possible. All notices shall be prepared consistent with the Commission’s plain language policy. Notice to the public concerning usage reductions shall be designed to avoid confusion in geographical areas served by more than one NGDC.

   The provisions of this §  59.72 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 2203(15) and 2208.

   The provisions of this §  59.72 adopted December 14, 2001, effective December 15, 2001, 31 Pa.B. 6800.

 (a)  An emergency exists whenever the aggregate demand of firm service customers on an NGDC’s system or confined segment of the system exceeds or threatens to exceed the gas supply or capacity that is actually and lawfully available to the NGDC to meet the demands, and the actual or threatened excess creates an immediate threat to the NGDC’s system operating integrity with respect to Priority 1 customers as defined in subsection (i).

 (b)  If, in the sole judgement of the NGDC, there is sufficient time, the NGDC shall use reasonable business and operational efforts to: interrupt all interruptible services, issue operational flow orders, and call for voluntary usage reductions by all customers before taking any action under subsection (c). The NGDC shall take these three actions sequentially to the extent feasible.

 (c)  In the event of an emergency under subsection (a), the NGDC may require each commercial and industrial retail and transportation customer that is not a Priority 1 customer under subsection (i) to reduce its consumption of gas.

   (1)  The reduction required shall be determined by the utility without regard to priorities of use, as necessary to minimize the potential threat to public health and safety.

   (2)  The minimum authorized usage may not be lower than the minimum usage of firm service necessary for plant protection use.

   (3)  When all other service has been curtailed except for Priority 1 service and the NGDC continues to be unable to meet Priority 1 requirements, the NGDC shall exercise its judgment as to any further curtailment that may be necessary and shall utilize measures designed to minimize harm to customers if curtailments to plant protection use are found to be necessary.

   (4)  Consistent with its responsibility to maintain system integrity at all times, the NGDC shall restore service as soon as practicable to any gas-fired electric generation facility that is deemed critical to electric system reliability by the electrical system’s control area operator.

 (d)  Mandatory reductions under subsection (c) shall be for a period specified by the NGDC until further notice. The NGDC may change a customer’s authorized usage, upon notice, at any time during an emergency.

 (e)  Mandatory reductions under subsection (c) shall be for a maximum duration of 5 business days unless extended by Commission order. As an alternative to extending mandatory reductions under subsection (c), the Commission may order the NGDC to initiate priority-based curtailments under subsection (f).

 (f)  In determining whether to order the NGDC to initiate priority-based curtailments, the Commission will examine whether the NGDC did the following:

   (1)  Interrupted all interruptible services.

   (2)  Issued operational flow orders.

   (3)  Called for voluntary usage reductions by all customers.

 (g)  Upon issuance of an order to initiate priority-based curtailments, the NGDC shall provide all affected customers the maximum notice possible, by means of telephone, fax or electronic data interchange, specifying the curtailment percentage of the customer’s firm gas service and resulting allowance as may be the case.

 (h)  Upon issuance of an order to initiate priority-based curtailments, the available gas supplies to the NGDC shall be prorated, if practicable, among its customers according to the following priorities of use:

   (1)  Customers in a higher priority category will not be curtailed until all customers falling into a lower priority category have been restricted to plant protection use levels, unless operational circumstances or physical limitations warrant a different result.

   (2)  Where only a partial restriction of a classification is required, implementation shall be pro rata, to the extent practical under the circumstances, as set forth in the NGDC’s tariff.

     (i)   Following are the priority categories, listed in descending order, pertaining to the curtailment of firm services:

   (1)  Priority 1. Service for essential human needs use.

   (2)  Priority 2. Firm services not included in essential human needs use.

 (j)  As part of its natural gas emergency plan, an NGDC may divide any or all of the priority of use categories in subsection (i) into subcategories.

   The provisions of this §  59.73 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 2203(15) and 2208.

   The provisions of this §  59.73 adopted December 14, 2001, effective December 15, 2001, 31 Pa.B. 6800.

 (a)  Each NGDC may restrict or discontinue service in accordance with this section and § §  59.71—59.73 and 59.75 without thereby incurring any penalty or liability for any loss, injury or expense that may be sustained by the customer except when the restriction or discontinuation of service is as a result of the NGDC’s willful or wanton misconduct.

 (b)  NGDC liability for actions taken under §  59.73 (relating to emergency action), or to a regulation, policy statement, directive or order issued by the Commission or an emergency order issued by the Governor shall be governed by the following principles:

   (1)  If an NGDC appropriates natural gas during an emergency action, the NGDC shall compensate the applicable entity, whether the customer or the customer’s NGS, for the cost of lost, firm gas service. The compensation, in the aggregate, shall equal but not exceed the greater of: the city gate cost of the appropriated natural gas, including transportation charges up to the NGDC’s city gate, or the reasonable cost actually paid by the customer for delivered substitute energy, as documented to the NGDC. NGDCs may provide compensation in kind only at the discretion of the affected customer or NGS.

   (2)  The NGDC may discontinue service, for the duration of an emergency, to a customer that continues to take gas in violation of the rules found in this subchapter.

   The provisions of this §  59.74 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 2203(15) and 2208.

   The provisions of this §  59.74 adopted December 14, 2001, effective December 15, 2001, 31 Pa.B. 6800.

 The tariff, operating practices, and billing periods of the NGDCs and their suppliers differ significantly. Therefore, each NGDC is permitted to utilize its own appropriate billing periods for calculating pipeline transportation, storage service, and balancing or other penalties and its own tariffed procedure for imposing those penalties on customers who take gas service and NGSs who operate in a manner that is contrary to the rules and regulations of this chapter.

   The provisions of this §  59.75 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 2203(15) and 2208.

   The provisions of this §  59.75 adopted December 14, 2001, effective December 15, 2001, 31 Pa.B. 6800.

   This section cited in 52 Pa. Code §  59.71 (relating to definitions); and 52 Pa. Code §  59.74 (relating to utility liability).

ANNUAL RESOURCE PLANNING REPORT

   The provisions of these § §  59.81—59.84 issued under the Public Utility Code, 66 Pa.C.S. § §  308(c), 501, 504, 523, 1319 and 1501, unless otherwise noted.

 (a)  For the purposes of this subchapter, each jurisdictional public utility with sales of 8 billion cubic feet per year or more including transportation volume shall submit to the Commission an annual integrated resource planning report. Except for Form 1A/2A, whose filing date is March 1, copies of the report shall be submitted on or before June 1, 1996, and June 1 of successive years. An original and five copies of the report shall be submitted. This report shall include a plan that includes the past year’s historical data, program changes, and the next 3-year forecast. One copy of the report shall also be submitted to the Office of Consumer Advocate, the Office of Small Busines Advocate and the Office of Trial Staff. The information contained within the report shall conform to the following requirements:

   (1)  The name and telephone number of persons having knowledge of the matters, and to whom inquiries should be addressed.

   (2)  A forecast of annual and peak day energy demand requirements in million cubic feet displayed by component parts, as indicated in Form-IRP-Gas-1A and Form-IRP-Gas-lB. The load growth projections shall reflect the effects of price elasticity, market-induced conservation, building and appliance efficiency standards and the effects of the utility’s existing and planned conservation and load management activities.

   (3)  A forecast of annual and peak day energy supply resources in million cubic feet indicating sources of presently available and new supplies which the utility estimates will become available displayed by component parts, as indicated in Form-IRP-Gas-2A, a list of contracts for gas transportation, to the reporting utility’s city gate, upstream of the city gate and related to transportation as indicated in Form-IRP-Gas-2B and a list of contracts for gas storage services provided to the reporting utility, as indicated in Form-IRP-Gas-2C.

   (4)  A forecast of the number of customers (year end) displayed by component parts, as indicated in Form-IRP-Gas-3.

   (5)  A summary forecast of annual and peak day energy supply resources and demand requirements in million cubic feet, as indicated in Form-IRP-Gas-4A and Form-IRP-Gas-4B.

   (6)  The data required under paragraphs (1)—(5) shall consist of the past 2 years actual historical data, the current year (both actual and projected) and a 3-year forecast. For the purpose of this section, the term “current year” refers to the year in which the filing is being made.

   (7)  A detailed discussion of the methodologies, data sources and assumptions used in preparing the information required by this section shall be included.

 (b)  The reporting formats referred to in this section are contained in §  59.84 (relating to formats). Annual data shall be submitted on a calendar year basis, January 1 through December 31. If the utility purchases gas on a contract basis other than a calendar year, the contract time interval shall be identified.

 (c)  Annual integrated resource planning reports submitted under subsection (a) shall be accompanied by a summary suitable for public distribution. The summary shall include an implementation plan specifying activities scheduled for the acquisition and development of the resources delineated in the report, which are to take place during the planning period. Utilities shall maintain copies of the summary open for public inspection during normal business hours.

 (d)  Informal sessions may be scheduled for reviewing integrated resource plans and providing an opportunity for interested parties to participate in the review process.

   The provisions of this §  59.81 amended June 23, 2000, effective June 24, 2000, 30 Pa.B. 3172. Immediately preceding text appears at serial pages (246438) to (246439).

 (a)  For purposes of this subchapter, each jurisdictional gas utility with sales of 8 billion cubic feet per year or more including transportation volume, shall submit its Annual Conservation Activities Report and incorporate it with the reporting requirements found at §  59.81(a) (relating to periodic reporting requirements for major gas utilities) on or before June 1 of each year except for Form 1 which is due March 1. The report shall contain a description of conservation and load management programs implemented or operational during the past calendar year and programs which are proposed to be implemented within 1 year following the filing of the 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 to reduce the peak or maximum load or demand, with little or no change in total annual energy use.

 (b)  The description shall conform to the Form-IRP-Gas-5 and shall contain:

   (1)  A descriptive title of the program.

   (2)  The purpose or objective.

   (3)  The details of program activity and implementation schedule.

   (4)  An accounting of the monetary and personnel resources actually or proposed to be expended or devoted to the program.

   (5)  The actual or anticipated results of the program in terms of energy savings, reduction of utility on peak demand or other appropriate measure of the program’s objective.

 (c)  The report shall also contain, for each class or type of energy user the number of customers in each class as of the end of the previous year, the total energy consumed by each class and the individual target consumption reductions for each class, as indicated on Form-IRP-Gas-6.

 (d)  The report shall include a summary of programs, as indicated on Form-IRP-Gas-7.

 (e)  For each program with an annual utility expenditure of more than $100,000 or more than 0.1% of total annual revenue, whichever is less, excepting informational, educational or research and development programs, the utility shall submit a cost-benefit analysis using the common evaluation methodology in §  59.83 (relating to evaluation methodology), as indicated on Forms-IRP-Gas-8 and IRP-Gas-9.

 (f)  The Commission, through its Bureau of Conservation, Economics and Energy Planning, may issue a list of specific conservation and load management programs which shall be considered for implementation by each designated utility. The utility shall provide information documenting the consideration of these and other conservation and load management options and supporting the utility’s decision of whether or not to implement the options.

 (g)  Utilities shall maintain copies of the annual conservation reports open to public inspection during normal business hours. Customers shall be notified, in writing, of the availability of the reports for public inspection. Notification may be included with customers’ monthly bills.

 (h)  The following forms have been provided for under this chapter as a format to be used in preparing the annual conservation report:

   (1)  Form-IRP-Gas-5—Program Description.

   (2)  Form-IRP-Gas-6—Energy Users.

   (3)  Form-IRP-Gas-7—Program Summary.

   (4)  Form-IRP-Gas-8—Cost-Benefit Analysis Inputs.

 For purposes of this subchapter, each jurisdictional utility with sales of 8 billion cubic feet per year or more including transportation volume, shall utilize benefit-cost methodologies as prescribed by the Bureau of Conservation, Economics and Energy Planning to evaluate the costs and benefits of conservation and load management programs, and demand-side management programs. The cost-benefit methodologies shall be utilized by the utility during the next program year after they are prescribed.

 In preparing the annual integrated resource planning reports required by §  59.81(a) (relating to periodic reporting requirements for major gas utilities), each jurisdictional utility shall use the forms and schedules specified by the Bureau of Conservation, Economics and Energy Planning, which shall include the following:

   (1)  Form-IRP-Gas-lA—Annual Gas Demand Requirements; Form-IRP-Gas-1B—Peak Day Gas Requirements.

   (2)  Form-IRP-Gas-2A—Natural Gas Supply; Form-IRP-Gas-2B—Natural Gas Transportation; Form-IRP-Gas-2C—Natural Gas Storage.

   (3)  Form-IRP-Gas-3—Number of Customers (Year End).

   (4)  Form-IRP-Gas-4A—Annual Supply and Demand Requirements Summary; Form-IRP-Gas-4B—Peak Day Supply and Demand Requirements Summary.

   (5)  Form-IRP-Gas-5—Program Description.

   (6)  Form-IRP-Gas-6—Energy Users.

   (7)  Form-IRP-Gas-7—Program Summary.

   (8)  Form-IRP-Gas-8—Cost-Benefit Analysis Inputs.

   (9)  Form-IRP-Gas-9—Cost-Benefit Analysis Results.

   The provisions of this §  59.84 amended June 23, 2000, effective June 24, 2000, 30 Pa.B. 3172. Immediately preceding text appears at serial pages (246441) to (246442).

   This section cited in 52 Pa. Code §  59.81 (relating to periodic reporting requirements for major gas utilities).

STANDARDS FOR CHANGING A CUSTOMER’S NATURAL GAS SUPPLIER

§ 59.91. Definitions.

 The following words and terms, when used in this section and § §  59.92—59.99, have the following meanings, unless the context clearly indicates otherwise:

   Customer—A retail gas customer as defined by 66 Pa.C.S. §  2202 (relating to definitions). The term includes all persons identified by the NGDC ratepayer of record, under §  59.95 (relating to persons authorized to act on behalf of a customer), as authorized to act on behalf of the NGDC ratepayer of record in changing the NGS for the account.

   Data element—One or more characters that represent numeric or alphanumeric fields of data.

   NGDC—Natural Gas Distribution Company—An NGDC as defined by 66 Pa.C.S. §  2202.

   NGS—Natural gas supplier—A supplier as defined by 66 Pa.C.S. §  2202.

   The provisions of this §  59.91 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 504—506, 1301 and 1501.

 When a customer orally contacts the NGDC to request a change of NGS, the NGDC shall notify the customer that the selected NGS shall be contacted directly to initiate the change.

   The provisions of this §  59.92 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 504—506, 1301 and 1501.

 When a contact occurs between a customer and an NGS to request a change of the NGS, upon receiving direct oral confirmation or written authorization from the customer to change the NGS, the customer’s new NGS shall:

   (1)  Notify the NGDC of the customer’s NGS selection by the end of the next business day following completion of the application process. The NGDC shall verify the accuracy of the information provided by the NGS by matching at least two data elements such as name and account number, or address and account number, with NGDC records.

   (2)  Upon receipt of this notification, the NGDC shall send the NGDC ratepayer of record a confirmation letter noting the proposed change of NGS. This letter shall include notice of a 10-day waiting period in which the order may be canceled before the change of the NGS takes place. The notice shall include the date service with the new NGS will begin unless the customer contacts the NGDC 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 a NGS.

   The provisions of this §  59.93 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 504—506, 1301 and 1501.

 When a customer has provided the NGS with oral confirmation or written authorization to change NGSs, the NGDC shall make the change at the beginning of the first feasible billing period following the 10-day waiting period, as prescribed in §  59.93 (relating to customer contacts with NGSs).

   The provisions of this §  59.94 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 504—506, 1301 and 1501.

 A customer may identify persons authorized to make changes to the customer’s account. To accomplish this, the customer shall provide the NGDC with a signed document identifying by name those persons who have the authority to initiate a change of the customer’s NGS.

   The provisions of this §  59.95 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 504—506, 1301 and 1501.

 A document signed by the customer whose sole purpose is to obtain the customer’s consent to change NGSs shall be accepted as valid and result in the initiation of the customer’s request. Documents not considered as valid include canceled checks, signed entries into contests and documents used to claim prizes won in contests.

   The provisions of this §  59.96 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 504—506, 1301 and 1501.

 (a)  When a customer contacts an NGDC or an NGS and alleges that the customer’s NGS 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 the requirements in § §  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 NGSs and the dispute investigation establishes that the change occurred without the customer’s consent, the customer is not responsible for NGS charges 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 natural gas supply charges.

 (c)  A customer who has had a NGS changed without having consented to that change shall be switched back to the original NGS for no additional fee. Charges involved in the switch back to the prior NGS shall be 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 NGS 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 NGS bills or administrative charges that might otherwise apply, rendered since the change of the NGS.

 (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 any NGS that demonstrates a pattern of violating this chapter. The Commission may order a particular NGS that has a pattern of violating this chapter to obtain written authorization from every new customer as a condition of providing service in this Commonwealth. Nothing in this section limits the Commission’s authority.

   The provisions of this §  59.97 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 504—506, 1301 and 1501.

 Sections 59.91—59.99 do not apply in instances when the customer’s service is discontinued by the NGS and subsequently provided by the provider of last resort because no other NGS is willing to provide service to the customer.

   The provisions of this §  59.98 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 504—506, 1301 and 1501.

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

   The provisions of this §  59.99 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 504—506, 1301 and 1501.

   The provisions of this §  59.99 adopted July 7, 2000, effective July 8, 2000, 30 Pa.B. 3451.