Revenue Procedure 2023-15
Internal Revenue Service
2023-18 I.R.B. 806
     
   
   
 26 CFR 1.263(a)-3: Amounts paid to improve tangible property.      
 (Also Part I, §§ 162, 165, 167, 168, 263(a), 263A, and 446; 1.165-7(a)(2), 1.167(a)-11, 1.168(i)-1, 1.446-1.)      
     
 Rev.Proc. 2023-15      
     
 TABLE OF CONTENTS      
     
                              
           
   
SECTION 1. PURPOSE   
     
This revenue procedure provides a safe harbor method of accounting that taxpayers may use to determine whether certain expenditures to maintain, repair, replace, or improve natural gas transmission and distribution property must be capitalized as improvements under § 263(a) of the Internal Revenue Code (Code) or as the costs of property produced by the taxpayer for use in its trade or business under § 263A, or are allowable as deductions under § 162.  1   This revenue procedure also provides procedures for taxpayers to obtain automatic consent to change their method of accounting to the safe harbor method of accounting permitted by this revenue procedure.   
     
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1     Unless otherwise specified, all "section" or "§" references are to sections of the Code or the Income Tax Regulations (26 CFR part 1).      
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SECTION 2. BACKGROUND.01 Taxpayers that transmit and distribute natural gas pay or incur significant expenditures to maintain, repair, replace, and improve natural gas transmission and distribution property. Generally, whether these expenditures are allowable as deductions under § 162 for repairs or maintenance or must be capitalized under § 263(a) as improvements to property depends on whether these expenditures result in a betterment or restoration of the property or adapt it to a new or different use. See  §§ 1.162-4 and 1.263(a)-3(d). Whether these expenditures are capitalized under § 263A depends, generally, on whether these expenditures are properly allocable to property produced by the taxpayer. See  §    1.263A-1(a)(3). Applying capitalization principles to natural gas transmission and distribution property can be particularly difficult, largely because the property consists of a network of interconnected assets. As a consequence, there often exists uncertainty as to whether certain costs to maintain, repair, replace, and improve parts or components of such interconnected property are capital expenditures or expenses allowable as deductions..02 To reduce uncertainty and associated disputes between taxpayers and the IRS regarding whether expenditures to maintain, repair, replace, or improve natural gas transmission and distribution property must be capitalized or are allowable as deductions, this revenue procedure provides a "natural gas transmission and distribution property safe harbor method of accounting" or "NGSH Method" (as defined under section 4.01 of this revenue procedure) for determining whether certain costs of maintaining, repairing, replacing, and improving natural gas transmission and distribution property are required to be capitalized under § 263(a) or § 263A, or may be treated as ordinary and necessary business expenses for which a deduction is allowable under § 162(a)..03 To apply the NGSH Method, a taxpayer must first classify its natural gas transmission and distribution property as either linear property (for example, pipes, fittings, and valves) or non-linear property (for example, compressors, regulators, and meters). If a taxpayer chooses to use the NGSH Method for its linear property, the taxpayer (1) must use the "safe harbor method for linear property" (as defined under section 4.02 of this revenue procedure) for all of the taxpayer's linear transmission and distribution property and (2)    may choose to apply the "safe harbor method for non-linear property" (as defined under section 4.03 of this revenue procedure) for all of the taxpayer's non-linear transmission and distribution property. However, if a taxpayer chooses to use the NGSH Method for its non-linear property, the taxpayer must use (1) the safe harbor method for non-linear property for all of the taxpayer's non-linear transmission and distribution property and (2) the safe harbor method for linear property for all of the taxpayer's linear transmission and distribution property..04 The safe harbor method for linear property provides different rules for linear transmission property (generally, linear property that transmits natural gas from production facilities to local distribution systems) and for linear distribution property (generally, linear property that distributes natural gas to local customers). For linear transmission property, the safe harbor method for linear property defines the appropriate units of transmission property and provides a simplified rule for determining whether the costs of replacing a portion of that unit of linear transmission property must be capitalized under §§ 263(a) and 263A. See  section 5.02 of this revenue procedure. For linear distribution property, the safe harbor method does not define units of property but divides distribution property into "distribution mains" and "distribution service lines" and provides simplified rules for determining whether the costs of replacing distribution mains and the costs of repairing, maintaining, replacing, or improving distribution service lines must be capitalized under §§ 263(a) and 263A. See  sections 5.03 and 5.07 of this revenue procedure. A taxpayer using the safe harbor method for linear property is required to use it for both its linear transmission property and its linear distribution property..05 The safe harbor method for non-linear property defines units of property and major components of non-linear transmission and distribution property and provides that a taxpayer must capitalize the costs of replacing a unit of non-linear property or a major component of a unit of non-linear property under §§ 263(a) and 263A. See  section 5.04 of this revenue procedure and Appendix A of this revenue procedure (Appendix A). In addition, if a taxpayer replaces a unit of non-linear property or a major component of a unit of non-linear property, the taxpayer must also capitalize the costs of any repairs, maintenance, or replacements that directly benefit or are incurred by reason of the replacement of the unit of non-linear property or major component of the unit of non-linear property. Except as otherwise provided in section 6.04 of this revenue procedure, if a taxpayer chooses to use the safe harbor method for non-linear property, the taxpayer must use this safe harbor method for all its non-linear transmission and distribution property..06 This revenue procedure also provides "per se capitalization rules" that apply to both linear and non-linear property. These per se capitalization rules identify certain costs that a taxpayer must treat as capital expenditures if the taxpayer utilizes the NGSH Method. See  section 5.05 of this revenue procedure. For example, in general, a taxpayer using the NGSH Method is required to capitalize the costs of additions and replacements that materially increase capacity to one or more customers. See  sections 5.05(1)(b) and (2) of this revenue procedure. Also, under the per se capitalization rules, a taxpayer using the NGSH Method must capitalize the costs of: (1) replacing all or part of property if the taxpayer deducts a loss for the replaced property (other than a casualty loss) or takes the adjusted basis of the replaced property into account in realizing gain or loss resulting from a sale or exchange of the replaced property; and (2) repairing and replacing all or part of property for which the taxpayer is required to take a basis adjustment as a result of a casualty loss or relating to a casualty event. These rules are referred to collectively as the "disposition/loss per se capitalization rules." See  section 5.05(1)(g) and (h) of this revenue procedure..07 Replacements of natural gas transmission and distribution property often involve dispositions of properties that are replaced. These dispositions generally require taxpayers to recognize gain or loss, or take a basis adjustment, thus triggering the disposition/loss per se capitalization rules under the NGSH Method. Accordingly, the NGSH Method would not be useful without providing a mechanism to mitigate the effects of these dispositions and the resulting application of the disposition/loss per se capitalization rules to a taxpayer utilizing this safe harbor method. Thus, a taxpayer using the NGSH Method must include costs capitalized under the NGSH Method in general asset accounts as described under § 168(i)(4) and § 1.168(i)-1(l). See  section 5.08 of this revenue procedure. The use of general asset accounts limits (1) the circumstances under which a taxpayer is required to recognize a loss on the disposition of property, and (2) the circumstances under which a taxpayer is required to take a casualty loss or a basis adjustment as a result of a casualty event. Therefore, the inclusion of transmission and distribution property in general asset accounts allows a taxpayer to avoid triggering the disposition/loss per se capitalization rules. The use of general asset accounts also allows a taxpayer to continue to depreciate this property after its disposition.   
     
In addition, to facilitate the transition to the use of general asset accounts, this revenue procedure requires a taxpayer using the NGSH Method to make a late general asset account election under §§ 168(i)(4) and § 1.168(i)-1(l) for natural gas transmission and distribution property that the taxpayer previously placed in service and owns at the beginning of its year of change. See  section 5.08(2) of this revenue procedure. Moreover, to incentivize taxpayers to use the NGSH method and to encourage taxpayers to change to the NGSH method for their first taxable year ending after May 1, 2023, this revenue procedure provides a special transition rule. Under this rule, if a taxpayer changes to the NGSH Method for its first taxable year ending after May 1, 2023, the taxpayer does not have to apply certain per se capitalization rules to amounts paid or incurred to replace or repair linear property or non-linear property, as applicable, in taxable years ending on or before May 1, 2023. See  section 5.08(3)(a) of this revenue procedure..08 The safe harbor method for linear property and the safe harbor method for non-linear property are methods of accounting under § 446. Section 446(e) and §    1.446-1(e) require taxpayers to secure the consent of the Commissioner of Internal Revenue (Commissioner) before changing a method of accounting for Federal income tax purposes. Section 1.446-1(e)(3)(ii) authorizes the Commissioner to prescribe administrative procedures setting forth the limitations, terms, and conditions necessary to permit a taxpayer to obtain consent to change a method of accounting. Section 6.05 of this revenue procedure provides the procedures by which a taxpayer may obtain automatic consent for a change in method of accounting to use the safe harbor method for linear property and the safe harbor method for non-linear property.   
     
SECTION 3. SCOPE.01 In general.    Only a taxpayer that meets both of the requirements of section 3.01(1) and (2) of this revenue procedure may choose to apply the NGSH Method.   
     
(1) The taxpayer has a depreciable interest in natural gas transmission or distribution property described in section 4 of this revenue procedure.   
     
(2) The taxpayer pays or incurs costs (other than costs described in section 3.03 of this revenue procedure) to maintain, repair, replace, or improve the particular property referenced in section 3.01(1) of this revenue procedure..02 Application to entities.   The determination of whether a taxpayer satisfies the requirements of both section 3.01(1) and (2) of this revenue procedure is made separately with respect to each member of a consolidated group and with respect to each partnership, S    corporation, or trust (other than a grantor trust)..03 Exclusions.    The NGSH Method does not apply to the following:   
     
(1) The costs of property for the transmission, distribution, control, or storage of natural gas at a marine liquefied natural gas terminal capable of shipping or receiving liquid natural gas for import or export;   
     
(2) The costs of enclosures or buildings suitable for occupation;   
     
(3) The costs of non-linear property that is not specifically identified in Appendix A (for example, tools, fixtures, furniture, computer equipment, and other miscellaneous equipment);   
     
(4) The costs of smart pipeline inspection gauges as defined in section 4.27 of this revenue procedure; and   
     
(5) The costs of cleaning pipeline inspection gauges as defined in section 4.28 of this revenue procedure.   
     
SECTION 4. DEFINITIONS   
     
The following definitions apply solely for purposes of this revenue procedure (including its appendices):.01 Natural gas transmission and distribution property safe harbor method of accounting. "Natural gas transmission and distribution property safe harbor method of accounting" or "NGSH Method" means the safe harbor method for linear property, the safe harbor method for non-linear property, and the other applicable rules set out in this revenue procedure, collectively, regardless of whether the taxpayer chooses to use both methods, or uses only the safe harbor method for linear property..02 Safe harbor method for linear property. "Safe harbor method for linear property" means the method of accounting described in sections 5.02, 5.03, and 5.07 of this revenue procedure in conjunction with the other applicable rules set forth in this revenue procedure..03 Safe harbor method for non-linear property. "Safe harbor method for non-linear property" means the method of accounting described in section 5.04 of this revenue procedure in conjunction with the other applicable rules set forth in this revenue procedure..04 Natural gas transmission property. "Natural gas transmission property" means real and personal property that is used to transport, control, and store natural gas at any point between (1) a gas processing plant or custody transfer point and (2) a city gate station or other delivery point, generally connecting to a natural gas distribution system. Gas production wells, gathering lines, and processing plants are not included in this definition..05 Natural gas distribution property. "Natural gas distribution property" means real and personal property that is used to transport, control, and store natural gas at any point between (1) a city gate station or other custody transfer point generally connecting to a transmission system, and (2) the customer gas meter or other delivery point to the customer. For this purpose, "natural gas distribution property" includes both (1) the city gate station or other custody transfer point and (2) the customer gas meter or other delivery point to the customer..06 Linear property. "Linear property" means all natural gas transmission and distribution property except non-linear property. Examples of linear property include pipes, valves, tunnels, casing, and fittings..07 Non-linear property. "Non-linear property" means all natural gas transmission and distribution property that is compressor station property, gas storage facility property, measuring and regulating station property, or meters or regulators, wherever located. Examples of non-linear property include compressors, tanks, liquefaction equipment, and structures..08 Work order. "Work order" means a written document that identifies and defines the scope of a specific project. A work order may include repairs, maintenance, replacements, and/or improvements to natural gas transmission or distribution property..09 Blanket work order. "Blanket work order" means a written document that authorizes a project or projects over a specific period of time, generally not exceeding one year. A blanket work order may include repairs, maintenance, replacements, and/or improvements to natural gas transmission or distribution property..10 Replacement. "Replacement" means the installation of property so that existing property can be removed from service, whether or not the existing property is physically removed. Generally, a replacement made pursuant to a work order is a single replacement for purposes of this revenue procedure, regardless of whether (1) the work is performed at the same or different times, and (2) in the case of linear property, the property that is replaced is contiguous or noncontiguous. Multiple replacements made under separate work orders or made pursuant to a blanket work order may be aggregated for purposes of applying the NGSH Method. See section 5.06 of this revenue procedure for the rules for aggregating costs related to linear and non-linear transmission and distribution property..11 City gate station. "City gate station" means a measuring and regulating station at which a distribution system receives natural gas, generally from a transmission system..12 Hydraulic subsystem. "Hydraulic subsystem" means all linear transmission property used to direct the flow of natural gas that is maintained within the same operating pressure range in the shortest section between any two of the following points:   
     
(1) a gas processing plant;   
     
(2) a compressor station at a storage facility;   
     
(3) a compressor station not described in section 4.12(2) of this revenue procedure (including between two compressor stations described in this section 4.12(3));   
     
(4) a regulator (including between two regulators);   
     
(5) the point where the taxpayer's distribution system begins; or   
     
(6) a custody transfer point where the gas is delivered to or from another party. For example, a regulator located between another regulator and a compressor station divides that section of linear transmission property into two separate hydraulic subsystems, even if both subsystems are maintained within the same operating pressure range..13 Compressor station property. "Compressor station property" means property that supplies the energy to move natural gas at increased pressure at storage facilities or in transmission lines, including but not limited to compressors, instrumentation and controls, meters, regulators, measuring equipment, odorizing equipment, gas detection equipment, electric supply equipment, equipment to maintain pipeline quality gas, mounting pads, buildings, and fencing or walls..14 Gas storage facility property. "Gas storage facility property" means property at an above ground or underground gas storage facility, including a compressed or liquefied natural gas storage facility, and an underground storage facility in a salt formation or a depleted well or well field. Gas storage facility property does not include property at a liquefied natural gas marine terminal capable of shipping or receiving liquefied natural gas for import or export..15 Measuring and regulating station property. "Measuring and regulating station property" means property at a location that measures or regulates natural gas, including but not limited to meters, regulators, and gauges..16 Measuring equipment. "Measuring equipment" means equipment used to measure the pressure or temperature of the gas. As used in this revenue procedure, the term does not include a meter that measures gas flow, as defined in section 4.23 of this revenue procedure..17 Instrumentation and controls. "Instrumentation and controls" means the analog and digital devices that measure, monitor, or control the equipment at storage facilities, compressor stations, and measuring and regulating stations (including city gate stations). Instrumentation and controls include SCADA (supervisory control and data acquisition) equipment and measuring and regulating equipment. As used in this revenue procedure, however, instrumentation and controls do not include assets that are treated as separate units of property (for example, meters or regulators)..18 Distribution main. "Distribution main" means a distribution line that serves as a common source of supply for more than one distribution service line. "Distribution mains" means more than one section of distribution main in a natural gas distribution system..19 Distribution service line. "Distribution service line" means a line that carries natural gas from the distribution main to the customer gas meter..20 Distribution service line costs. "Distribution service line costs" means direct and indirect costs paid or incurred to repair, maintain, replace, or improve distribution service lines..21 Lateral line. "Lateral line" means a line in a natural gas distribution or transmission system that branches away from the central and primary part of the system..22 Compressor. "Compressor" means a mechanical device for increasing the pressure of gas..23 Meter. "Meter" means an instrument for measuring and indicating or recording the flow of gas that has passed through it..24 Regulator. "Regulator" means a device that reduces the pressure in a gas line and maintains the pressure within a constant band..25 Well. "Well" means a cased bore hole used for gas input or output for an underground storage reservoir, including a storage well..26 Equipment to maintain pipeline quality gas. "Equipment to maintain pipeline quality gas," also known as "purification equipment," means equipment used to ensure that the gas moving through a line is maintained within certain parameter. This term includes, but is not limited to, the equipment used to remove liquids and impurities from the gas, and the equipment used to heat or cool the gas to make it suitable for movement through the line..27 Smart pipeline inspection gauges. "Smart pipeline inspection gauges," also known as "smart pigs," are devices that are equipped with sensors that gauge the thickness of pipes they are traveling through and detect cracks, fissures, erosion and other problems that may affect the integrity of the pipeline. Smart pipeline inspection gauges are not included within the definition of natural gas transmission or distribution property for purposes of this revenue procedure..28 Cleaning pipeline inspection gauges. "Cleaning pipeline inspection gauges," also known as "cleaning pigs," are devices that have brushes, scrapers, or similar tools and are used for cleaning pipelines by removing sedimentation and build-up that can impede the flow of gas. Cleaning pipeline inspection gauges are not included within the definition of natural gas transmission or distribution property for purposes of this revenue procedure..29  Odorizing equipment. "Odorizing equipment" means equipment that injects an odorant or other additive into the gas so that leaks can be detected by the sense of smell..30 Gas detection equipment. "Gas detection equipment" means equipment that indicates the existence of natural gas in a specific area..31 Electric supply equipment. "Electric supply equipment" means equipment that supplies electricity to equipment at a compressor station or gas storage facility, including but not limited to generators, batteries and chargers, and transformers..32 Liquefaction equipment. "Liquefaction equipment" means equipment that is used in connection with the liquefaction of natural gas, including but not limited to cold boxes, heat exchangers, condensers, and vaporizing units..33 Cathodic protection. "Cathodic protection" means a technique to prevent the corrosion of a metal surface by making that surface the cathode of an electrochemical cell.   
     
SECTION 5. NATURAL GAS TRANSMISSION AND DISTRIBUTION PROPERTY SAFE HARBOR METHOD OF ACCOUNTING.01 In general.     
     
(1) A taxpayer using the NGSH Method must apply the safe harbor method for linear property provided in sections 5.02 and 5.03 of this revenue procedure to the direct and indirect costs of replacing all its linear transmission and distribution main property, including any unit of property rules described therein. A taxpayer using the NGSH Method must also apply the safe harbor method for distribution service line costs as provided in section 5.07 of this revenue procedure. Moreover, a taxpayer using the NGSH Method may, but is not required to, apply the safe harbor method for non-linear property provided in section 5.04 of this revenue procedure to the direct and indirect costs of repairing, maintaining, replacing, and improving all its non-linear transmission and distribution property, including the application of the units of property and major components described in Appendix A. In addition, except as provided in section 5.08(3)(a) of this revenue procedure, a taxpayer using the NGSH Method must apply the per se capitalization rules provided in section 5.05 of this revenue procedure and the aggregation rules provided in section 5.06 of this revenue procedure to property subject to the NGSH Method. Finally, a taxpayer using the NGSH Method must include certain costs of natural gas transmission and distribution property in general asset accounts as provided in section 5.08 of this revenue procedure.   
     
(2) Solely for purposes of this revenue procedure, the IRS will respect a reasonable and consistently applied designation of property by the taxpayer as either transmission or distribution property for Federal or State regulatory purposes, whichever is applicable. If the taxpayer is unregulated, the IRS will respect a reasonable and consistently applied designation that the taxpayer uses for its books and records.   
     
(3) A taxpayer may not rely on the unit of property definitions provided in this revenue procedure for any other purpose of the Code or regulations, including for determining the unit of property under other sections of the Code or determining the asset for depreciation purposes (including placed in service, retirements, dispositions, or classification under § 168(e) or Rev.Proc. 87-56, 1987-2 C.B. 674) for the same or similar type of assets.   
     
(4) Amounts required to be capitalized under the NGSH Method are capital expenditures and must be taken into account through a charge to capital account or basis. Amounts that are paid or incurred for MACRS property and that are capitalized under this NGSH Method are accounted for in the manner described in section 5.08 of this revenue procedure..02 Safe harbor method for linear property--application to transmission property.   
     
(1) Unit of property for linear transmission property. For purposes of this revenue procedure, the unit of property for linear natural gas transmission property is the linear property within each hydraulic subsystem as defined in section 4.12 of this revenue procedure. If a transmission segment is composed of two or more parallel lines, each line between each compressor station or other connection point is a separate unit of property. A lateral line on a transmission line is not a separate unit of property unless there is a compressor station or regulator at the junction point between the lateral line and the main transmission line. If a lateral line can be treated as part of a unit of property with more than one main transmission line, the taxpayer should designate the main line with which the lateral line is associated and follow that designation consistently.   
     
(2) Simplified rule for replacements of linear transmission property. Whether a taxpayer using the safe harbor method for linear property must capitalize the cost of a replacement of linear transmission property is determined by the length of the line replaced. If more than 10 percent of the length of the unit of linear transmission property is replaced, the cost of the replacement must be capitalized under §§ 263(a) and 263A. If 10 percent or less of the length of the unit of linear transmission property is replaced, the cost of the replacement is not required to be capitalized under § 263(a) or § 263A. The cost of the replacement includes the direct and indirect costs of replacing the pipe and any associated linear property, including, but not limited to, connectors, cathodic protection, valves, casing, tunnels, instrumentation and controls, and structural supports for such property.   
     
(3) Blanket work orders.   
     
(a) Allocation. To the extent a taxpayer cannot specifically identify whether amounts charged to a blanket work order are for a replacement of linear transmission property greater than 10 percent of the unit of linear transmission property, the taxpayer may use any reasonable method to allocate costs charged to the blanket work order if the reasonable method is consistently applied by the taxpayer.   
     
(b) De minimis charges. A taxpayer that adheres to a policy that limits per-event charges under a blanket work order to replacements of property costing $50,000 or less is not required to capitalize the costs of replacing linear transmission property charged to the blanket work order. Replacements of property qualifying under this de minimis rule are not taken into account in determining whether more than 10 percent of the length of the unit of linear transmission property is replaced under section 5.02(2) of this revenue procedure or in applying the aggregation requirement in section 5.06 of this revenue procedure..03 Safe harbor method for linear property--application to distribution property.   
     
(1) In general. For purposes of determining whether the costs of replacing linear distribution property must be capitalized under the NGSH Method, the unit of linear distribution property is not defined. Instead, the taxpayer must initially determine whether the costs are for the replacement of distribution mains as defined in section 4.18 of this revenue procedure or are distribution service line costs as defined in section 4.20 of this revenue procedure. To determine whether the costs of replacing distribution mains must be capitalized, the taxpayer must apply the simplified rule provided in section 5.03(2) of this revenue procedure. To determine whether distribution service line costs must be capitalized, the taxpayer must apply the simplified rules provided in section 5.07 of this revenue procedure.   
     
(2) Simplified rule for replacements of distribution mains. Whether a taxpayer using the safe harbor method for linear property must capitalize the cost of replacing distribution mains is determined by the length of the distribution mains replaced. If more than four miles of distribution mains are replaced, the cost of the replacement must be capitalized under §§ 263(a) and 263A. If four miles or less of distribution mains are replaced, the cost of the replacement is not required to be capitalized under § 263(a) or § 263A. The cost of the replacement includes the direct and indirect costs of replacing the distribution mains and any associated linear property, including, but not limited to, connectors, cathodic protection, valves, casing, tunnels, instrumentation and controls, and structural supports for such linear property.   
     
(3) Blanket work orders.   
     
(a) Allocation. To the extent a taxpayer cannot specifically identify whether amounts charged to a blanket work order are for the replacement of distribution mains greater than four miles, the taxpayer may use any reasonable method to allocate costs charged to the blanket work order if the reasonable method is consistently applied by the taxpayer.   
     
(b) De minimis charges. A taxpayer that adheres to a policy that limits per-event charges under a blanket work order to replacements of property costing $50,000 or less is not required to capitalize the costs of distribution mains replacements charged to the blanket work order. Replacements of property qualifying under the de minimis rule in this section 5.03(3)(b) are not taken into account in determining replacement length under section 5.03(2) of this revenue procedure or in applying the aggregation requirement in section 5.06 of this revenue procedure..04 Safe harbor method for non-linear property - application to transmission and distribution property.   
     
(1) Applicability. A taxpayer may use the safe harbor method for non-linear property only if the taxpayer uses the safe harbor method for linear property. However, a taxpayer is not required to apply the safe harbor method for non-linear property if it uses the safe harbor method for linear property. If a taxpayer does not use the safe harbor method for non-linear property, then the taxpayer must apply §§ 162, 263(a), 263A, and the regulations thereunder to determine the appropriate units of property for its non-linear property and to determine whether amounts paid or incurred to repair, maintain, replace, or improve these units of property must be capitalized.   
     
(2) Units of property under the safe harbor method for non-linear property. For purposes of applying the safe harbor method for non-linear property, the units of property and corresponding major components of non-linear property are identified in Appendix A. A taxpayer that uses a unit of property definition provided in Appendix A must also use the major component definitions provided in Appendix A for that unit of property. Similarly, a taxpayer that uses a major component definition provided in Appendix A must also use the unit of property definition provided in Appendix A associated with that major component.   
     
(3) Simplified rule for replacements of non-linear property. The safe harbor method for non-linear property applies to the direct and indirect costs paid or incurred to repair, maintain, replace, or improve the taxpayer's non-linear transmission and distribution property. If the taxpayer replaces a unit of non-linear property or a major component of a unit of non-linear property as identified in Appendix A, then the taxpayer must capitalize the amounts paid to replace the unit of non-linear property or major component of the unit of non-linear property under §§    263(a) and 263A. In addition, if a taxpayer replaces a unit of non-linear property or a major component of a unit of non-linear property, the taxpayer must also capitalize the costs of any repairs, maintenance, or replacements that directly benefit or are incurred by reason of the replacement of the unit of non-linear property or major component of the unit of non-linear property. If the taxpayer pays or incurs amounts to repair, maintain, replace, or improve non-linear transmission or distribution property, but does not replace either a unit of non-linear property or a major component of a unit of non-linear property as part of these activities, then the taxpayer is not required to capitalize the amounts paid or incurred for such activities under § 263(a) or § 263A. However, if a taxpayer pays or incurs amounts to repair, maintain, replace, or improve its non-linear transmission or distribution property, and these costs relate to per se capital expenditures described under section 5.05 of this revenue procedure, then the amounts paid or incurred must be capitalized under section 5.05 of this revenue procedure..05 Per se capital expenditures.   
     
(1) In general. Except as provided in section 5.08(3)(a) of this revenue procedure, a taxpayer using the NGSH Method must capitalize the direct and indirect costs described in section 5.05(1)(a) through (j) of this revenue procedure to the extent these costs are paid or incurred with respect to linear property or non-linear property subject to the NGSH Method, notwithstanding any other provision of this revenue procedure. Per se capital expenditures include:   
     
(a) The costs of property necessary to add one or more new customers;   
     
(b) The costs of materially increasing capacity of the property to one or more existing or potential customers (see section 5.05(2) of this revenue procedure for the application of this rule to linear property);   
     
(c) The costs of adding a unit of non-linear property or adding a major component of a unit of non-linear property other than as a replacement, as defined in section 4.10 of this revenue procedure, for an existing major component;   
     
(d) The costs of property that extends a transmission or distribution system (see section 5.05(3) of this revenue procedure for the application of this rule to the costs of additional linear property required to relocate or replace an existing line);   
     
(e) The costs of property that adds cathodic protection, protective wrapping, or protective coating to linear property;   
     
(f) The costs of adding instrumentation and control equipment, including remote actuation or monitoring equipment, to property that did not previously have similar equipment; for these purposes, new instrumentation and control equipment is not similar if it provides additional functionality;   
     
(g) The costs of replacing all or part of property if the taxpayer deducts a loss for the replaced property (other than a casualty loss), or takes the adjusted basis of the replaced property into account in realizing gain or loss resulting from a sale or exchange of the replaced property;   
     
(h) The costs of repairing or replacing all or part of property as a result of damage for which the taxpayer is required to take a basis adjustment as a result of a casualty loss under §    165, or relating to a casualty event described in § 165;   
     
(i) The costs of easements or other rights in real property; and   
     
(j) The costs of adapting property to a new or different use.   
     
(2) Materially increasing capacity of linear property.   
     
(a) Determining materiality. For purposes of applying section 5.05(1)(b) of this revenue procedure to linear transmission property or linear distribution property, an expenditure for linear property materially increases capacity to one or more existing or potential customers if the work performed increases capacity by more than five percent to one or more existing or potential customers. In the case of transmission property, an increase in capacity is determined based on the increase in the capacity of the hydraulic subsystem, measured in terms of millions of cubic feet per day. In the case of distribution property, an increase in capacity is determined based on the increase in the throughput of gas to one or more existing or potential customers served or to be served by the added or replaced property, measured in terms of thousands of cubic feet per hour. For purposes of section 5.05(1)(b) of this revenue procedure, an increase in capacity does not include amounts paid to return linear property to its original capacity prior to any wear, tear, or other damage necessitating such expenditure.   
     
(b) Taxpayer's purpose. A taxpayer is not required to capitalize costs that materially increase capacity to linear property under section 5.05(2)(a) of this revenue procedure if the taxpayer can establish with reasonable certainty, through its books and records, that the principal purpose of an addition or replacement of linear property was for safety reasons, to standardize its system, or to comply with regulatory requirements, unrelated to increasing capacity. However, these costs may be subject to capitalization under sections 5.02, 5.03, or 5.07 of this revenue procedure or other per se capitalization rules under this section 5.05.   
     
(3) Property that extends a system. For purposes of applying section 5.05(1)(d) of this revenue procedure, the cost of property that extends a transmission or distribution system does not include the cost of additional linear property required to relocate or replace an existing line that will continue to run between the same two endpoints. However, if more than 10 percent of the length of the original unit of property is replaced, in the case of a replacement of linear transmission property, the costs of the replacement must be capitalized under section 5.02(2) of this revenue procedure. If more than four miles of distribution mains is replaced, in the case of a replacement of distribution mains, the cost of the replacement must be capitalized under section 5.03(2) of this revenue procedure.   
     
(4) Special rule for identified distribution service line costs associated with distribution mains. If the taxpayer can identify with reasonable accuracy distribution service line costs associated with distribution main costs that are treated as per se capital expenditures under this section 5.05, then the identified distribution service line costs are also treated as per se capital expenditures under this section 5.05. For rules regarding identified and unidentified distribution service line costs, see section 5.07 of this revenue procedure.   
     
(5) Coordination with other rules. Replacements of property for which the replacement costs are per se capital expenditures under this section 5.05 are not taken into account in determining whether more than 10 percent of the length of the unit of linear transmission property is replaced for purposes of applying section 5.02 of this revenue procedure, or in determining whether more than four miles of distribution mains are replaced for purposes of section 5.03 of this revenue procedure.   
     
(6) Examples. The following examples illustrate the application of this section 5.05. In each example, it is assumed that (a) the taxpayer is a corporation and files its Federal income tax return on an accrual method and a calendar year basis, (b) the taxpayer uses the safe harbor method for linear property and the safe harbor method for non-linear property for all its natural gas transmission and distribution property, and (c) the taxpayer does not make an election under § 1.168(i)-1(e)(3)(ii) (disposition of all assets remaining in a general asset account) or § 1.168(i)-1(e)(3)(iii) (disposition of an asset in a qualifying disposition). In addition, for the following examples, it is assumed that none of the aggregation requirements of section 5.06 of this revenue procedure apply.   
     
(a) Example 1. (i) Z  is a local natural gas distribution company that supplies gas to an industrial customer via a three-inch diameter distribution service line. Due to planned expansion of its facility, the customer will require more gas than can be supplied via the existing line. Z 's records include correspondence with the customer indicating that Z  agreed to install a second three-inch distribution service line and a second meter to meet the customer's need for additional gas at its facility. As a result of Z 's installation of a second three-inch distribution service line, throughput of gas to the customer is increased by 100 percent.   
     
(ii) The cost of installing the second distribution service line is a per se capital expenditure under section 5.05(1)(b) of this revenue procedure because it increases Z 's capacity to its customer by more than five percent and Z 's records reflect that the distribution service line is added for the principal purpose of increasing capacity to Z 's customer. The cost of installing a second meter must be capitalized under the per se capitalization rule in section 5.05(1)(c) of this revenue procedure because the new meter is an addition of a unit of non-linear property defined in section 2.04 of Appendix A.   
     
(b) Example 2. Y  is a natural gas transmission company that owns and operates a natural gas transmission pipeline that is 300 miles in length. Section A of this pipeline runs for 80 miles between two compressor stations, and is a hydraulic subsystem that is a unit of property. The pipe in Section A is 12 inches in diameter, except for a seven-mile segment that is 10 inches in diameter. Y  incurs costs to replace the seven-mile 10-inch segment with 12-inch pipe in order to increase the capacity of Section A. As a result of the replacement, the capacity of Section A to Y 's customers, as measured in terms of millions of cubic feet of gas per day, increased by more than five percent. In addition, Y 's records do not specifically indicate a principal purpose for replacing the seven-mile segment. Accordingly, the cost of replacing the existing 10-inch transmission line with the larger 12-inch transmission line must be capitalized as a per se capital expenditure under section 5.05(1)(b) of this revenue procedure.   
     
(c) Example 3. X  is a natural gas transmission company that owns and operates a natural gas transmission pipeline that is 300 miles in length. Section B of this transmission pipeline runs for 80 miles between two compressor stations and is a hydraulic subsystem that is a unit of property. The pipe in Section B is 10 inches in diameter. X  replaces seven miles of Section B with 12-inch pipe. As a result of the replacement, the capacity of Section B to X 's customers, as measured in terms of millions of cubic feet of gas per day, increased by two percent. Because the replacement did not result in an increase in Section B's capacity by more than five percent, the cost of replacing the seven miles of pipe is not a per se capital expenditure under section 5.05(1)(b) of this revenue procedure and, because less than 10 percent of Section B (7 miles out of 80 miles = 8.8 percent) is replaced, the cost is not required to be capitalized under section 5.02(2) of this revenue procedure.   
     
(d) Example 4. (i) W  is a local natural gas distribution company that supplies gas to a group of existing customers via an older three-inch diameter distribution main and individual distribution service lines. Pursuant to regulatory requirements, W  performs regular safety risk assessments that take into account the age and composition of the pipeline at various locations. Based on this safety assessment, W  determines it is necessary to replace three miles of distribution mains. The distribution main is replaced with four-inch diameter pipe, which is one of the standard sizes currently used by W  for all distribution main replacements. W 's books and records indicate that the principal purpose of the replacement was the result of the safety risk assessment. W  can identify with reasonable accuracy the distribution service line costs that are associated with the distribution mains replacement.   
     
(ii) Pursuant to section 5.05(2)(b) of this revenue procedure, the cost to replace the distribution main is not a per se capital expenditure under section 5.05(1)(b) of this revenue procedure because the taxpayer's books and records indicate that the principal purpose of the distribution main replacement was to reduce safety risk. Additionally, because the length of the distribution main replacement is less than four miles, the cost of the distribution main replacement is not required to be capitalized under section 5.03(2) of this revenue procedure. Similarly, because W  can identify the costs of replacing the distribution service lines with the distribution main replacement, the cost of replacing the associated distribution service lines is not a per se capital expenditure under section 5.05(1)(b) of this revenue procedure and is not required to be capitalized under section 5.07(2)(b)(ii) of this revenue procedure.   
     
(e) Example 5. (i) V  is a local natural gas distribution company that supplies natural gas to a group of existing customers at the edge of its service area via three miles of three-inch diameter distribution main, and individual distribution service lines. V 's records reflect that certain customers were experiencing gas delivery issues. Consequently, V  replaces the entire three-mile segment with four-inch diameter pipe, as well as the associated service lines. V 's books and records do not indicate any principal purpose of replacing the three-mile segment of distribution main other than to address its customer's gas delivery issues. V 's replacement of the three-mile segment of distribution main increased the throughput of gas to its existing customers by seven percent.   
     
(ii) Because the replacement of the distribution main results in an increase in the throughput of gas to the customers served by the distribution main of more than five percent, the cost to replace the three miles of distribution mains is a per se capital expenditure under section 5.05(1)(b) of this revenue procedure. Additionally, because the cost of the distribution main replacement is a per se capital expenditure, the cost of replacing the associated distribution service lines is a per se capital expenditure under sections 5.05(4) and 5.07(2)(a) of this revenue procedure.   
     
(f) Example 6. (i) U  is a local natural gas distribution company that owns and operates 160 miles of distribution mains. U 's distribution mains currently include one-, two-, three-, and four-inch diameter pipe. The diameters and materials vary depending on the year of installation. U  is currently standardizing its distribution mains by using pipe in two-inch and four-inch diameters. Any distribution main pipe that is replaced is replaced with one of these two standard sizes. U  replaces 875 feet of three-inch diameter pipe with four-inch diameter pipe, which had the effect of increasing its throughput to one or more existing or potential customers by more than five percent. U 's books and records indicate that its use of the larger diameter pipe was necessary to standardize its system with currently available sizes of pipe.   
     
(ii) Because U 's books and records indicate that the replacement is made to standardize its system, pursuant to section 5.05(2)(b) of this revenue procedure, the cost of the replacement is not a per se capital expenditure under section 5.05(1)(b) of this revenue procedure. Finally, because less than four miles of the distribution main pipe is replaced, the cost of the replacement is not required to be capitalized under section 5.03(2) of this revenue procedure.   
     
(g) Example 7. (i) T  is a local natural gas distribution company that owns and operates 160 miles of natural gas distribution mains. T 's distribution mains include iron pipe and polyethylene pipe. T  is currently using polyethylene pipe when it needs to replace pipe in its distribution mains because it considers polyethylene pipe to be better pipe for several reasons. T  replaces three miles of four-inch diameter iron pipe in its distribution mains with four-inch diameter polyethylene pipe. There is no change in the throughput of gas to customers served by the distribution main as a result of this replacement.   
     
(ii) The cost of the replacement is not a per se capital expenditure under section 5.05(1)(b) of this revenue procedure because the replacement does not materially increase capacity to one or more existing or potential customers. Additionally, because the distribution main replacement is for four miles or less, the cost of the replacement is not required to be capitalized under section 5.03(2) of this revenue procedure.   
     
(h) Example 8. S, a local natural gas distribution company, is required to relocate a distribution main to accommodate construction of a road. In order to reroute its distribution main around the construction site, S  replaces one mile of pipe and also adds 1,000 feet of pipe to the distribution system. Notwithstanding the addition of pipe to the distribution system, the cost of the relocation is not a per se capital expenditure under section 5.05(1)(d) of this revenue procedure because the pipeline continues to run between the same two endpoints. Additionally, the cost of the relocation is not required to be capitalized under section 5.03(2) of this revenue procedure because the replacement of distribution main pipe is four miles or less..06 Aggregation requirements.   
     
(1) General rule. For purposes of determining whether the applicable thresholds for capitalization of property provided in sections 5.02, 5.03, and 5.04 of this revenue procedure are met, a taxpayer must aggregate multiple replacements if all of the following requirements are met:   
     
(a) The replacements are within -   
     
(i) the same unit of property, for non-linear property and linear transmission property, or   
     
(ii) the same five-digit United States Postal Service ZIP Code delivery area, for linear distribution property;   
     
(b) The replacements are described in one authorizing document, as defined in section 5.06(2) of this revenue procedure; and   
     
(c) The authorizing document -   
     
(i) identifies the property with respect to which the replacements will occur or the locations where property will be replaced;   
     
(ii) identifies the amount of pipe to be replaced, or total cost of the replacements; and   
     
(iii) provides that the replacements are expected to be completed within five years after the date of the authorizing document. If the authorizing document does not provide a time period over which replacements will be completed, this requirement will be considered to be met unless it is determined upon original authorization that it will take more than five years to complete the replacements.   
     
(2) Authorizing document.   
     
(a) For purposes of this section 5.05 of this revenue procedure, the term "authorizing document" means the following:   
     
(i) a regulatory commission decision that requires replacements as part of an identified program aimed at a specific purpose;   
     
(ii) a written project authorization aimed at a specific purpose;   
     
(iii) a work order as defined under section 4.08 of this revenue procedure; or   
     
(iv) a blanket work order as defined under section 4.09 of this revenue procedure and which is aimed at a specific purpose.   
     
(b) A regulatory commission decision does not include a decision, whether or not designated as an "order," that authorizes expenditures for replacements but does not require replacements to be made.   
     
(3) General and specific authorizing documents. If replacements are described by a general authorizing document as well as one or more specific authorizing documents (for example, a regulatory commission decision and a written project authorization implementing the regulatory commission decision), aggregation is based on the most general authorizing document that meets the requirements of section 5.06(1)(c) of this revenue procedure. For example, if a general authorizing document provides that replacements are not expected to be completed within five years of this authorizing document, then aggregation of the replacements pursuant to this authorizing document is not required. However, if a subsequent more specific authorizing document implementing that same program or project provides that certain replacements are expected to be completed within five years of this subsequent authorizing document, then aggregation of the replacements described in the subsequent authorizing document is required, provided that the other requirements described in section 5.06(1) of this revenue procedure are met.   
     
(4) Aggregation of replacements across multiple years. Multiple replacements that meet the requirements described in section 5.06(1) of this revenue procedure are aggregated without regard to whether they are performed in one year or multiple years.   
     
(5) Modifications. Modifications to an authorizing document, or to the work done pursuant to an authorizing document, that occur within the taxable year are taken into account in determining whether to aggregate replacements, and whether to capitalize the expenditures, in that taxable year, but do not affect the aggregation of replacements pursuant to that authorizing document in a prior taxable year.   
     
(6) Anti-abuse rule. If a taxpayer acts (a) to divide closely related transmission or distribution property replacement projects into multiple written project authorizations, work orders, or blanket work orders or (b) to mischaracterize the intended or expected scope of a project, in order to avoid the application of the aggregation rules under this section 5.06, rather than for non-tax business reasons, appropriate adjustments will be made by the Commissioner to carry out the purposes of this revenue procedure.   
     
(7) Examples. The following examples illustrate the application of this section 5.06. In each example, it is assumed that (a) the taxpayer is a corporation and files its Federal income tax return on an accrual method and a calendar year basis, (b) the taxpayer uses the safe harbor method for linear property and the safe harbor method for non-linear property for all its natural gas transmission and distribution property, and (c) the taxpayer does not make an election under § 1.168(i)-1(e)(3)(ii) (disposition of all assets remaining in a general asset account) or § 1.168(i)-1(e)(3)(iii) (disposition of an asset in a qualifying disposition).   
     
(a) Example 1. (i) R  is a natural gas distribution company in State A. The Public Utility Commission (Regulator) of State A  sets the rates and approves tariffs for R. Regulator issues Rate Order 12345 as a result of certain rate proceedings. Rate Order 12345 allows for the incremental recovery of up to an additional $30 million annually in revenue through rates and tariffs. Rate Order 12345 states that these dollars are for the recovery of incremental operating expense, maintenance expense, and return on investment related to the replacement of distribution mains in its natural gas distribution system; however, no specific replacements are required, and Rate Order 12345 does not provide a time period over which replacements will be completed. R  makes annual filings documenting such costs, which match revenue billed to incremental expense and include R 's allowed return on investment. The specific distribution main replacements are determined by R  based on known conditions and risk analysis.   
     
(ii) For purposes of determining whether the replacement costs are capitalized under section 5.03 of this revenue procedure, aggregation of pipeline replacements is not required under this section 5.06 because Rate Order 12345 (A) does not identify a program aimed at a specific purpose for the replacements; (B) does not require specific replacements to be made; (C) does not identify the property with respect to which the replacements will occur or the locations for the replacements; (D) does not identify the amount of pipe or the total cost of the replacements; and (E) does not specify that the replacements are within the same Zip Code. All these criteria must be satisfied for the aggregation requirement of this section 5.06 to apply to replacements performed under Rate Order 12345.   
     
(b) Example 2. Q  is a local natural gas distribution company. Based on estimated general maintenance and upgrade costs and anticipated revenues through its rates and tariffs, Q  budgets $100 million during Year 1 for replacements within its distribution system. For purposes of determining whether the distribution main replacement costs are capitalized under section 5.03 of this revenue procedure, an aggregation of pipeline replacements is not required under this section 5.06 because Q 's budget document is not a written project authorization aimed at a specific purpose.   
     
(c) Example 3. P  is a local natural gas distribution company. P  issues a blanket work order for replacements of less than 2,000 feet of distribution mains. The blanket work order is used predominantly for the repair of leaks, but does not establish a project aimed at a specific purpose. P  performs several replacements under the blanket work order to repair leaks. For purposes of determining whether the replacement costs are capitalized under section 5.03 of this revenue procedure, an aggregation of distribution main replacements under the blanket work order is not required under this section 5.06 because the blanket work order is not an authorizing document under section 5.06(2) of this revenue procedure.   
     
(d) Example 4. (i) O  is a natural gas distribution company in State B. Following an explosion near a population center in State B  that may be attributable to Type L  pipe deteriorating faster than anticipated, Regulator issues an order in Year 1 requiring all Type L  pipe used in the transmission or distribution of natural gas or other combustible material in State B  to be replaced within five years to eliminate a safety risk to State B  citizens. The order also specifies procedures for applying for a special tariff to support replacements of Type L  pipe. In response to this order, O 's management instructs its engineering department to initiate a project to identify all Type L  pipe in its distribution system in State B. O  issues a written project authorization that will involve a review of its purchases of Type L  pipe, physical identification of the pipe, and inspection of sections of pipeline. As the locations of Type L  pipe are identified, O  prepares work orders to replace the Type L  pipe. In one ZIP Code delivery area, O  identifies six sections of Type L  distribution mains, totaling eight miles, and each of these sections are replaced under six separate work orders, as they are identified. Each work order identifies the location and the amount of the distribution mains to be replaced. Each work order is for a replacement of less than four miles of distribution mains.   
     
(ii) For purposes of determining whether the replacement costs are capitalized under section 5.03 of this revenue procedure, the replacements are not aggregated under this section 5.06 under the Regulator's order because, although the order is an authorizing document within the meaning of section 5.06(2) of this revenue procedure, the order does not identify the amount or costs of the distribution mains to be replaced, as required by section 5.06(1)(c)(ii) of this revenue procedure. Similarly, the replacements are not aggregated under the written project authorization issued by O  because the authorization does not identify the amount or the costs of the distribution mains to be replaced. See section 5.06(1)(c)(ii) of this revenue procedure. Rather, each of the six work orders qualify as separate authorizing documents under section 5.06(2) of this revenue procedure and provides the information required in section 5.06(1)(c). Because neither the Regulator's order nor the written project authorization meets the requirements for aggregation under this section 5.06, and each work order constitutes a separate authorizing document for the replacement of less than four miles of distribution mains, the costs of the replacements are not required to be capitalized under section 5.03 of this revenue procedure.   
     
(e) Example 5. (i) The facts are the same as in Example 4, except that in response to the Regulator's order, in Year 1, O 's management issues a written project authorization for the replacement of all Type L  pipe in County Z  in State B, identifying the quantity and location of all Type L  pipe in County Z, and authorizing $2 million for this purpose. County Z  falls within two ZIP Code delivery areas, Area F  and Area G. The project authorization does not provide a time period in which the replacements will be completed but there is no reason to expect that the project will take longer than five years.   
     
(ii) For purposes of determining whether the replacement costs are capitalized under section 5.03 of this revenue procedure, the replacements are aggregated under this section 5.06 pursuant to O 's written project authorization, which authorizes the replacement of distribution mains for a specific purpose and identifies the location of the replacements and the amount of distribution mains to be replaced. Accordingly, for each of the ZIP Code delivery areas affected by the written project authorization, replacements within that ZIP Code delivery area that are covered by the written project authorization are aggregated, even though the replacements may be noncontiguous, may occur over more than a single year, and may involve several work orders. The aggregate replacements in Area F  total seven miles, and the aggregate replacements in Area G  total three miles. Accordingly, under section 5.03 of this revenue procedure, the replacement costs of distribution mains in Area F  are capitalized and the replacement costs of distribution mains in Area G  are not required to be capitalized.   
     
(f) Example 6. (i) The facts are the same as in Example 4  except O  knows that it also has Type L  pipe in its distribution systems in State Y. In response to Regulator's order, O  issues a written project authorization authorizing its crews in State Y  to replace all Type L  pipe that is more than 10 years old as Type L  pipe is encountered in the normal course of operations. It is reasonable to expect that the replacements under this project authorization would not be completed within five years. During Year 2, O  exceeds its capital maintenance budget in State Y  by $1 million. A review of the work orders charged to the project authorization during Year 2 indicates that O  spent $2 million on replacing 12 miles of functional Type L  distribution mains. One work order authorized the replacement of six miles of distribution mains at different locations within ZIP Code delivery Area H  at a cost of $ 1.2 million. The remaining three work orders each authorized the replacement of two miles of distribution mains at different locations within ZIP Code delivery Area J.   
     
(ii) For purposes of determining whether the replacement costs are capitalized under section 5.03 of this revenue procedure, the replacements of Type L  distribution mains in State Y  in Year 2 are not aggregated under this section 5.06 under O 's written project authorization, because the written project authorization does not specify the amount of mains or the total cost of replacements, or the period over which the replacements are to occur and it is reasonable to expect that the replacements will not be completed within five years. However, the replacement of six miles of distribution mains pursuant to the work order charged in Year 2 authorizing the replacement of six miles of distribution mains at specified locations within ZIP Code delivery Area H  is aggregated under this section 5.06 because this work order meets the requirements of section 5.06(1) of this revenue procedure and constitutes an authorizing document. See  section 5.06(3) of this revenue procedure. Although the other three work orders are for replacements of distribution mains within the same ZIP Code delivery area, these work orders are not aggregated because they constitute separate authorizing documents. Because each of these three work orders is for the replacement of less than four miles of distribution mains, the costs of these distribution main replacements are not required to be capitalized under section 5.03 of this revenue procedure.   
     
(g) Example 7. (i) M  is a natural gas distribution company. M  budgets $10 million for the replacement of distribution mains that run through subdivisions A  and B, which are in ZIP code delivery area H. The budget directs the work to be done through a written project authorization, which is issued in Year 1. The work under the written project authorization is reasonably expected to be completed in late Year 2 or early Year 3. The priority of replacements will be determined based on risk assessments, but the written project authorization calls for the eventual replacement of five miles of distribution mains in ZIP code delivery area H.   
     
(ii) For purposes of determining whether the replacement costs are capitalized under section 5.03 of this revenue procedure, aggregation is not required by the general budget because the budget does not qualify as an authorizing document under section 5.06(2) of this revenue procedure. However, the replacements done pursuant to the written project authorization are aggregated under this section 5.06 because the document is aimed at a specific purpose, authorizes the replacement of a known amount of distribution mains in a certain location and, although it does not specify the time period over which replacements will be completed, there is no reason to expect that completing the replacements will take longer than five years. Because the aggregate replacements of distribution mains within ZIP Code area H  total more than four miles, the costs to replace the five miles of distribution mains are capitalized under section 5.03 of this revenue procedure.   
     
(h) Example 8. (i) L  is a natural gas transmission company that operates a natural gas transmission line in State C. In Year 1, L  conducts an internal inspection of a 100-mile section of the transmission line, a hydraulic subsystem that is a separate unit of property under section 5.02(1) of this revenue procedure. An analysis of the survey indicates that 11 miles (11 percent) of the pipe in this section should be removed and replaced due to deterioration. In a written project authorization issued in January of Year 1, L 's management authorized $22 million to replace the 11 miles of pipe and directed that the work commence as soon as practicable. The project is expected to be completed in Year 1. Based on a study of actual deterioration in removed pipe versus the deterioration shown by the inspection device, L 's engineers determine in November of Year 1 that the replacement of only nine miles (9 percent) is warranted. The replacement of the nine miles, which was performed under two separate work orders, is completed in December of Year 1.   
     
(ii) For purposes of determining whether the replacement costs are capitalized under section 5.02 of this revenue procedure, the replacements are required to be aggregated under this section 5.06 pursuant to the January, Year 1, authorization, which meets the requirements of section 5.06(1) and (2) of this revenue procedure. Under section 5.06(5) of this revenue procedure, the aggregation determination is based on the status of the written project authorization and the work done, or to be done, at the end of each taxable year. As of the end of Year 1, it was known that only nine miles of the transmission line were replaced. Because the aggregated replacements total less than 10 percent of the unit of linear transmission property, the cost of the replacements is not required to be capitalized under section 5.02 of this revenue procedure.   
     
(i) Example 9. (i) The facts are the same as in Example 8, except that the January Year 1 project authorization required the replacement of only nine miles (9 percent) of L 's 100-mile hydraulic subsystem. In November of Year 1, L 's engineers then determined that a total of 11 miles (11 percent) had to be replaced, and the replacement of 11 miles was completed in December of Year 1.   
     
(ii) For purposes of determining whether the replacement costs are capitalized under section 5.02 of this revenue procedure, the replacement work is aggregated pursuant to the January Year 1 project authorization, which meets the requirements of section 5.06(1) and (2) of this revenue procedure. Under section 5.06(5) of this revenue procedure, the aggregation determination is based on the status of the written project authorization and the work done, or to be done, at the end of each taxable year. It was known as of the end of Year 1 that more than 10 percent of the unit of property was replaced, as aggregated under this section 5.06 pursuant to the January Year 1 project authorization. Accordingly, the cost of the replacements in Year 1 must be capitalized under section 5.02 of this revenue procedure.   
     
(j) Example 10. (i) The facts are the same as in Example 8, except that when the January Year 1 written project authorization is issued, L 's management expects that the work will not be completed until Year 3. The work commences in Year 1 and continues in Years 2 and 3. In Year 3, based on a study of actual deterioration in removed pipe versus that shown by the inspection device, L 's engineers determine that the replacement of only nine miles (9 percent) of the 100-mile section is warranted, rather than the 11 miles (11 percent) originally anticipated. In December of Year 3, L 's engineers issue the final work order, authorizing the replacement of two additional miles of pipe, and the work is completed. In aggregate, only nine total miles of pipe are replaced under the written project authorization.   
     
(ii) For purposes of determining whether the replacement costs are capitalized under section 5.02 of this revenue procedure, the replacement work expected to be performed in Year 1, Year 2, and Year 3 is aggregated pursuant to the January Year 1 project authorization, which meets the requirements of sections 5.06(1) and (2) of this revenue procedure. Because the replacement of more than 10 percent of the unit of property was authorized in January of Year 1, the costs of the replacements that are incurred in Year 1 and Year 2 are capitalized. Under section 5.06(5) of this revenue procedure, the aggregation determination is based on the status of the written project authorization and the work done, or to be done, as of the close of each taxable year, and modifications do not affect the aggregation of replacements in prior taxable years. Therefore, the fact that only a total of nine miles (nine percent of the 100-mile unit of property) was eventually replaced does not affect the tax treatment of the replacement costs incurred in Year 1 and Year 2. However, the costs incurred in Year 3 are not required to be capitalized because, at the end of Year 3, L  knows that only nine percent of the unit of property was replaced under the Year 1 project authorization.   
     
(k) Example 11. (i) The facts are the same as in Example 10, except that pursuant to L 's initial survey, the January Year 1 written project authorization requires the replacement of only nine miles of pipe (nine percent of the 100-mile unit of property). Eight miles are replaced in Years 1 and 2. In Year 3, L 's engineers determine that five additional miles of pipe should be replaced for a total of 13 miles and request that management modify the project and authorize additional funds to complete the 13-mile replacement. The project authorization is modified accordingly, and replacement of the remaining five miles is completed by December of Year 3.   
     
(ii) For purposes of determining whether the replacement costs are capitalized under section 5.02 of this revenue procedure, the costs of the replacements expected to be performed in Years 1 through 3 were aggregated under this section 5.06 pursuant to the Year 1 project authorization, which meets the requirements of sections 5.06(1) and (2). Under section 5.06(5) of this revenue procedure, the aggregation determination was based on the status of the written project authorization and the work done, or to be done, as of the close of each taxable year, and modifications would not affect the aggregation of replacements in prior taxable years. Accordingly, the costs incurred in Years 1 and 2 are not required to be capitalized because, as of the end of each of those taxable years, the total replacements required by the project authorization were not expected to exceed 10 percent of the unit of property. Pursuant to section 5.06(5) of this revenue procedure, however, the cost of the five miles replaced in Year 3 is required to be capitalized, because, as of the end of Year 3, it was known that a total of 13 miles (13 percent of the unit of property) were replaced pursuant to the Year 1 project authorization..07 Safe harbor method for linear property - rules for distribution service line costs.   
     
(1) In general. A taxpayer using the safe harbor method for linear property must determine the amount of distribution service line costs that must be capitalized using the rules described in sections 5.07(2) and 5.07(3) of this revenue procedure. The rules in section 5.07(2) of this revenue procedure determine the treatment of distribution service line costs that a taxpayer can identify with reasonable accuracy as paid or incurred for a project described in section 5.07(2) of this revenue procedure. The rules in section 5.07(3) of this revenue procedure determine the treatment of distribution service line costs that the taxpayer is unable to identify with reasonable accuracy as paid or incurred for a project described in section 5.07(2) of this revenue procedure.   
     
(2) Rules for identified distribution service line costs. To the extent that a taxpayer can identify, with reasonable accuracy, distribution service line costs, the following treatment applies to the identified costs:   
     
(a) Identified costs that are per se capital expenditures. Identified distribution service line costs that are per se capital expenditures described under section 5.05 of this revenue procedure, including distribution service line costs associated with distribution main costs that are per se capital expenditures described under section 5.05 of this revenue procedure, are required to be capitalized.   
     
(b) Identified costs other than per se capital expenditures.   
     
(i) Identified distribution service line costs, other than per se capital expenditures described in section 5.07(2)(a) of this revenue procedure, associated with distribution main replacements that are required to be capitalized under section 5.03(2) of this revenue procedure (that is, associated with distribution main replacements that are more than four miles), are required to be capitalized;   
     
(ii) Identified distribution service line costs, other than per se capital expenditures described in section 5.07(2)(a) of this revenue procedure, associated with distribution main replacements that are not required to be capitalized under section 5.03(2) of this revenue procedure (that is, associated with distribution main replacements that are four miles or less), are not required to be capitalized; and   
     
(iii) Identified distribution service line costs, other than per se capital expenditures described in section 5.07(2)(a) of this revenue procedure, not associated with distribution main replacements (for example, the replacement of a customer's service line only) are not required to be capitalized.   
     
(3) Simplified rules for unidenti   fi   ed distribution service line costs.    To the extent a taxpayer cannot identify distribution service line costs with reasonable accuracy as provided under section 5.07(2) of this revenue procedure, the simplified rules in this section 5.07(3) apply to determine the amount of such costs to be capitalized under §§ 263(a) and 263A. Step 1 determines the total amount of unidentified distribution service line costs. Steps 2 through 4 determine the capitalization ratio that applies to such costs. In Step 5, the taxpayer multiplies the total amount of unidentified distribution line costs determined in Step 1 by the capitalization ratio to determine the amount of its unidentified distribution service line costs that are required to be capitalized.   
     
(a) Step 1. Determine total unidentified distribution service line costs. To determine the total unidentified distribution service line costs, the taxpayer's total distribution service line costs for the taxable year are reduced by the identified distribution service line costs described in section 5.07(2) of this revenue procedure.   
     
(b) Step 2. Determine total distribution main replacement costs not associated with identified distribution service line costs (denominator of capitalization ratio). To determine the total distribution main replacement costs not associated with identified distribution service line costs for purposes of the denominator in the capitalization ratio, the taxpayer's total distribution main replacement costs, including distribution main replacement costs qualifying under the de minimis rule for blanket orders under section 5.03(3)(b) of this revenue procedure, paid or incurred in the taxable year are decreased by the following:   
     
(i) Distribution main replacement costs that are required to be capitalized as per se capital expenditures under section 5.05 of this revenue procedure;   
     
(ii) Distribution main replacement costs associated with identified distribution service line costs required to be capitalized under section 5.07(2)(b)(i) of this revenue procedure; and   
     
(iii) Distribution main replacement costs associated with identified distribution service line costs not required to be capitalized under section 5.07(2)(b)(ii) of this revenue procedure.   
     
(c) Step 3. Determine capitalized distribution main replacement costs not associated with identified distribution service line costs (numerator of capitalization ratio). To determine the capitalized distribution main replacement costs not associated with identified distribution service line costs for purposes of the numerator in the capitalization ratio, the taxpayer's total costs of distribution main replacements that are required to be capitalized under section 5.03(2) of this revenue procedure are decreased by any amount of distribution main replacement costs associated with identified distribution service line costs required to be capitalized under section 5.07(2)(b)(i) of this revenue procedure (the amount determined in section 5.07(3)(b)(ii) of this revenue procedure).   
     
(d) Step 4. Determine capitalization ratio. To determine the capitalization ratio, divide the taxpayer's capitalized distribution main replacement costs not associated with identified distribution service line costs that were capitalized, as determined under Step 3, by the taxpayer's total distribution main replacement costs not associated with distribution service line costs, as determined under Step 2.   
     
(e) Step 5. Determine the portion of unidentified distribution service line costs that must be capitalized. To determine the portion of unidentified distribution service line costs that must be capitalized, multiply the taxpayer's capitalization ratio, as determined under Step 4, by the taxpayer's total unidentified distribution service line costs determined under Step 1.   
     
(f) Formula. The following formula reflects the rule provided in this section 5.07(3):   
     
           
     
(4) Example.   
     
(a) Facts. K  is a corporation that operates a natural gas distribution system in State D. K  files its Federal income tax return on an accrual method and a calendar year basis and uses the NGSH Method. K  uses work orders and blanket work orders to authorize replacement and repair work on its distribution system. K 's work orders detail the scope of each individual project and capture direct and indirect costs for labor, construction, and materials. K 's work orders for the replacement of distribution mains identify the distribution service lines that are replaced in conjunction with these distribution main replacements.   
     
In Year 1, K  incurs costs of $9 million with respect to replacements of linear distribution property. Of this amount, K  incurs $8 million for replacements of distribution mains (including $1 million in distribution main replacement costs qualifying under the de minimis rule for blanket work orders), and K  incurs $1 million for distribution service lines costs. Of the $1 million K  incurs for work on distribution service lines, K  incurs $150,000 for distribution service line costs that are per se capital expenditures, including distribution service line costs associated with distribution mains, the costs of which are per se capital expenditures. K  incurs $60,000 for distribution service line costs that are capitalized under the NGSH Method because they are associated with distribution main replacements of more than four miles, and K  incurs $140,000 for distribution service line costs that are not required to be capitalized under the NGSH Method because they are associated with distribution main replacements of four miles or less. K  also incurs $100,000 for distribution service line costs, other than per se capital expenditures, not associated with distribution main replacements. Of the $8 million K  incurs for replacement of distribution mains, K  incurs $2 million for per se capital expenditures related to distribution mains, $1.5 million for distribution main replacements exceeding four miles, and $3.5 million for distribution main replacements of four miles or less. K  can associate $600,000 of the $1.5 million K  incurs for distribution main replacements exceeding four miles with identified distribution service line costs that are capitalized under section 5.07(2)(b)(i) of this revenue procedure. K  can also associate $2.5 million of the $3.5 million K  incurs for distribution main replacements of four miles or less with identified distribution service line costs that are not required to be capitalized under section 5.07(2)(b)(ii) of this revenue procedure.   
     
(b) Step 1. To determine its total unidentified distribution service line costs, K  begins with the $1 million it incurs for its work on distribution service lines for Year 1 and subtracts its identified distribution service line costs for Year 1. These identified distribution service lines costs are the sum of (i) $150,000, K 's distribution service line costs that are per se capital expenditures under section 5.07(2)(a) of this revenue procedure, (ii) $60,000, K 's distribution service line costs that are capitalized under section 5.07(2)(b)(i) of this revenue procedure because they are associated with distribution main replacements of more than four miles, (iii) $140,000, K 's distribution service line costs that are not capitalized under section 5.07(2)(b)(ii) of this revenue procedure because they are associated with distribution main replacements of four miles or less, and (iv) $100,000, K 's distribution service line costs that are identified under section 5.07(2)(b)(iii) of this revenue procedure as not associated with any distribution main replacements. Thus, K 's total identified distribution service line costs equals $450,000 ($150,000 + $60,000 + $140,000 + $100,000). K  subtracts the total identified distribution service line costs of $450,000 from the total distribution service line costs it incurs for the taxable year of $1 million. The net result of $550,000 ($1 million - $450,000) is the total unidentified distribution service line costs.   
     
(c) Step 2. K  then determines the total distribution main replacement costs not associated with identified distribution service line costs by taking the total costs incurred in Year 1 with respect to distribution main replacement property of $8 million (which includes the $1,000,000 for expenditures of less than $50,000 on blanket work orders qualifying under the de minimis rule) and decreasing these costs by (i) $2 million, the distribution main replacement costs that are per se capital expenditures under section 5.05 of this revenue procedure; (ii) $600,000, the distribution main replacements costs associated with identified distribution service line costs that are capitalized under section 5.07(2)(b)(i) of this revenue procedure; and (iii) $2.5 million, the distribution main replacements costs associated with identified distribution service line costs that are not required to be capitalized under section 5.07(2)(b)(ii) of this revenue procedure. The net result of $2.9 million ($8 million - ($2 million + $600,000 + $2.5 million)) comprises the total distribution main replacement costs not associated with identified distribution service line costs.   
     
(d) Step 3. Next, K  determines the total costs of distribution main replacements that are capitalized under section 5.03(2) of this revenue procedure to be $1.5 million because such costs are for distribution main replacements over four miles. Then, K  reduces this amount by $600,000, the distribution main replacement costs associated with identified distribution service line costs that are capitalized under section 5.07(2)(b)(i) of this revenue procedure. The difference, $900,000, represents the total capitalized costs of distribution main replacements that were not associated with identified service line costs.   
     
(e) Step 4. K  then determines the capitalization ratio to be applied to its total unidentified distribution service line costs by dividing the total capitalized cost of distribution main replacements that are not associated with identified distribution service line costs of $900,000 by the total costs of distribution main replacements that are not associated with distribution service line costs of $2.9 million. The quotient of 0.31 ($900,000 / $2.9 million) is the capitalization ratio.   
     
(f) Step 5. Finally, K  determines the unidentified distribution service line costs that must be capitalized by multiplying the capitalization ratio of 0.31 by the total unidentified service line costs of $550,000. The product of $170,500 (0.31 x $550,000) is the unidentified distribution service line costs that must be capitalized..08 General asset accounts and transition rules.      
     
(1) Requirement to use general asset accounts. A taxpayer using the NGSH Method must make a general asset account election under § 168(i)(4) and § 1.168(i)-1(l) to include in general asset accounts certain natural gas transmission and distribution property that is MACRS property, as defined in § 1.168(b)-1(a)(2). The following property must be included in general asset accounts:   
     
(a) Certain property placed in service in or after year of change. Natural gas transmission and distribution property that is capitalized under the NGSH Method, that is MACRS property, and that is placed in service by the taxpayer in or after the taxable year for which the taxpayer adopts or changes to the NGSH Method. See § 1.168(i)-1(l) for time and manner of making a general asset account election for such property; and   
     
(b) Certain property placed in service before year of change. Natural gas transmission and distribution property described in section 5.08(2)(a) of this revenue procedure. See section 5.08(2) of this revenue procedure for the application of general asset accounts to this property.   
     
(2) Late general asset election required for certain property placed in service before year of change.   
     
(a) In general. A taxpayer that changes to the NGSH Method must change its method of accounting to the NGSH Method on either a cut-off basis, as permitted under section 6.04 of this revenue procedure, or with a § 481(a) adjustment as described in sections 6.01, 6.02, and 6.03 of this revenue procedure. A taxpayer that changes to the NGSH Method of accounting with a cut-off or § 481(a) adjustment must also make a late general asset account election under § 168(i)(4) and § 1.168(i)-1(l) to include certain transmission and distribution property in general asset accounts. Specifically, for property for which the taxpayer did not make a general asset account election (as defined in section 5.08(2)(d) of this revenue procedure), the taxpayer must make a late general asset account election to include in general asset accounts certain MACRS property placed in service by the taxpayer in taxable years prior to the year of change and owned by the taxpayer at the beginning of the year of change, as follows:   
     
(i) Change made in taxpayer's first, second, or third taxable years with a § 481(a) adjustment. If a taxpayer changes to the NGSH Method for the taxpayer's first, second, or third taxable year ending after May 1, 2023, with a § 481(a) adjustment, the taxpayer must make a late general asset account election for linear and non-linear property, as applicable, that is described in section 5.08(2)(a) of this revenue procedure and that is capitalized under the NGSH Method as a result of this method change. See section 5.08(3)(a) of this revenue procedure for a special rule providing exceptions to certain per se capital expenditure rules applicable to a taxpayer that changes to the NGSH Method for its first taxable year ending after May 1, 2023 with a § 481(a) adjustment.   
     
(ii) Change made in taxpayer's first, second, or third taxable years on a cut-off basis. If a taxpayer changes to the NGSH Method for the taxpayer's first, second, or third taxable year ending after May 1, 2023  on a cut-off basis under section 6.04 of this revenue procedure, the taxpayer must make a late general asset account election for linear and non-linear property, as applicable, that is described in section 5.08(2)(a) of this revenue procedure and that was capitalized by the taxpayer under its prior method of accounting in taxable years prior to the year of change.   
     
(iii) Change made in fourth or subsequent taxable years. If a taxpayer changes to the NGSH Method for the taxpayer's fourth taxable year ending after May 1, 2023, or for any subsequent taxable year, the taxpayer must make a late general asset account election for linear and non-linear property, as applicable, that is described in section 5.08(2)(a) of this revenue procedure, that is capitalized, or that should have been capitalized under §§ 263(a) and 263A and the corresponding regulations in taxable years prior to the year of change. See section 5.08(3)(b) of this revenue procedure for special rules applying to a taxpayer that changes in its fourth or subsequent taxable year.   
     
(iv) Year of change. For purposes of section 5.08 of this revenue procedure, "year of change" refers to the taxable year for which the taxpayer changes to the safe harbor method for linear property, the taxable year for which the taxpayer changes to both the safe harbor method for linear property and the safe harbor method for non-linear property, or the taxable year for which the taxpayer changes to the safe harbor method for non-linear property if the taxpayer had previously changed to and continues to apply the safe harbor method for linear property.   
     
(b) Time and manner of making late general asset account election. A taxpayer that changes to the safe harbor method for linear property must make the late general asset account election for property described in section 5.08(2)(a) of this revenue procedure on its original Federal income tax return or information return, as applicable, for the first taxable year that the taxpayer changes to the safe harbor method for linear property. A taxpayer that changes to the safe harbor method for non-linear property must make the late general asset account election for property described in section 5.08(2)(b) of this revenue procedure on its original Federal income tax return or information return for the first taxable year that the taxpayer changes to the safe harbor method for non-linear property. The IRS will treat the making of a late general asset account election under this section 5.08(2) as a change in method of accounting under § 446(e). The manner of making this change in method of accounting is described in section 6.05 of this revenue procedure.   
     
(c) Effect of late general asset account election. By making a late general asset account election described in this section 5.08(2) of this revenue procedure, the taxpayer consents to, and agrees to apply, all the provisions of § 1.168(i)-1 to the natural gas transmission and distribution property included in any general asset account. See  § 1.168(i)-1. Accordingly, if the taxpayer's present methods of accounting are not in accord with §    1.168(i)-1, the taxpayer must change to the methods of accounting permitted under § 1.168(i)-1 no later than the first taxable year that the taxpayer uses the natural gas transmission and distribution property safe harbor method of accounting.   
     
(d) Property for which the taxpayer did not make a general asset account election. For any property described in section 5.08(2)(a) of this revenue procedure, the term "property for which the taxpayer did not make a general asset account election" refers to any property for which the taxpayer:   
     
(i) Did not make a general asset account election for property in accordance with § 1.168(i)-1(l), or its predecessor § 1.168(i)-1(k);   
     
(ii) Did not make a late general asset account election under section 6.32(1)(a)(i) of Rev.Proc. 2015-14, 2015-5 I.R.B. 450, or section 6.32(1)(a)(i) of the APPENDIX to Rev.Proc. 2011-14, 2011-4 I.R.B. 330, as modified and clarified by Rev.Proc. 2014-17, 2014-12 I.R.B. 661; or   
     
(iii) Revoked a general asset account election pursuant to section 6.11(1)(a) of Rev.Proc. 2016-29, 2016-21 I.R.B. 880, section 6.34(1)(a) of Rev.Proc. 2015-14, or section 6.34(1)(a) of the APPENDIX to Rev.Proc. 2011-14.   
     
(3) Special rules for certain years of change.    
     
(a) Changes made in the taxpayer's first taxable year with a §      481(a) adjustment--certain per se capital expenditure rules not applied in prior years. If a taxpayer changes to the safe harbor method for linear property or for both linear property and non-linear property, as applicable, for the taxpayer's first taxable year ending after May 1, 2023 with a § 481(a) adjustment, the per se capital expenditure rules of section 5.05(1)(g) and (h) of this revenue procedure do not apply to amounts paid or incurred to replace or repair linear property or both linear property and non-linear property, as applicable, in taxable years ending on or before May 1, 2023.   
     
(b) Changes made in taxpayer's fourth or subsequent taxable years.   
     
(i) Taxpayer required to make change on a cut-off basis. A taxpayer that changes to the safe harbor method for linear property for the taxpayer's fourth taxable year ending after May 1, 2023, or for any subsequent taxable year, must make the change on a cut-off basis, and is not eligible to use the NGSH Method rules provided in sections 5.02, 5.03, 5.05, 5.06, and 5.07 of this revenue procedure for any linear property expenditures paid or incurred prior to the year of change. A taxpayer that changes to the safe harbor method for non-linear property for the taxpayer's fourth taxable year ending after May 1, 2023, or for any subsequent taxable year, must make this change on a cut-off basis, and is not eligible to use the NGSH Method rules provided in sections 5.04, 5.05, and 5.06 of this revenue procedure for any non-linear property expenditures paid or incurred prior to the year of change.   
     
(ii) Concurrent change. If a taxpayer changes to the safe harbor method for linear property or the safe harbor method for non-linear property for the taxpayer's fourth taxable year ending after May 1, 2023, or for any subsequent taxable year, and did not properly capitalize under §§ 263(a) and 263A any linear property expenditures or non-linear property expenditures, as applicable, paid or incurred prior to the year of change, the taxpayer also must change its method of accounting to properly capitalize such expenditures under §§    263(a) and 263A for the same year of change. The taxpayer must change to a method of accounting described under sections 11.08, 12.01, 12.02, 12.08, and/or 12.12 of Rev.Proc. 2022-14, 2022-7 I.R.B. 1, as applicable, and such method change must be made on the same Form 3115, Application for Change in Accounting Method, on which the taxpayer changes to the safe harbor method for linear property and the safe harbor method for non-linear property, as applicable.   
     
(4) Examples. The following examples illustrate the application of this section 5.08. In each example, it is assumed that the taxpayer (i) is a C corporation that files its Federal income tax returns on an accrual method and a calendar taxable year basis, (ii) is within the scope of this revenue procedure, (iii) placed in service natural gas transmission property or distribution property that is described in section 4 of this revenue procedure and is MACRS property, (iv) did not make a general asset account election for any natural gas transmission property or distribution property placed in service by the taxpayer in any taxable year before the first taxable year that the taxpayer uses the NGSH Method, (v) is changing its methods of accounting for both linear and non-linear property under the NGSH Method for the same taxable year, and (vi) is not changing to the NGSH Method on a cut-off basis under section 6.04 of this revenue procedure. It is also assumed, unless otherwise stated, that the costs of linear and non-linear property replacements before Year 1 were not capitalized under § 263(a), that these costs would not have been required to be capitalized under sections 5.02, 5.03, 5.04, 5.06, and 5.07 of this revenue procedure, and that these costs would not have been treated as per se capital expenditures under sections 5.05(1)(a)-(f), (i), or (j) of this revenue procedure. Further, it is assumed that § 1.168(i)-1(e)(3) (special rules for certain dispositions of assets in general asset accounts) does not apply for the first taxable year that the taxpayer uses the NGSH Method and for any subsequent taxable year. Moreover, for purposes of these examples, "Year 1" refers to the taxpayer's first taxable year ending after May 1, 2023, "Year 2" refers to the tax-payer's second taxable year ending after May 1, 2023, and "Year 4" refers to the taxpayer's fourth taxable year ending after May 1, 2023. The following examples do not address the treatment of depreciation or the requirement or computation of the § 481(a) adjustment, if applicable, for purposes of changing the taxpayer's methods of accounting under section 6 of this revenue procedure.   
     
(a) Example 1. (i) J  is a natural gas transmission company. Before Year 1, J  owned and placed in ser-vice natural gas transmission property at a cost of $100 million before any dispositions or additions. Before Year 1, J  replaced parts of such property that had an original cost of $10 million and incurred $12 million for the cost of such replacements. On its Federal income tax returns before Year 1, J  recognized losses upon the dispositions of that $10 million of property and deducted $12 million for the cost of the replacements under § 162(a). J  files a Form 3115 with its Federal income tax return for Year 1 to change its methods of accounting for linear and non-linear property to use the NGSH Method.   
     
(ii) Pursuant to the special rule in section 5.08(3)(a) of this revenue procedure, the per se capital expenditure rules in section 5.05(1)(g) and (h) of this revenue procedure do not apply to the replacement cost of $12 million that J  deducted under § 162(a) before J 's Year 1. Accordingly, this $12 million cost of the replacements is not a per se capital expenditure under the NGSH Method.   
     
(iii) At the beginning of Year 1, J  owns natural gas transmission property at a cost of $90 million ($100 million - $10 million). Because Year 1 is J 's first taxable year ending after May 1, 2023, J  must make a late general asset account election on its Form 3115 to include in general asset accounts all of the $90 million of natural gas transmission property that J  owns at the beginning of Year 1.   
     
(b) Example 2. (i) The facts are the same as the facts in Example 1, except that, during Year 1, J  replaced a part of the natural gas transmission property that had an original cost of $2 million and incurred $3.5 million for the cost of such replacements.   
     
(ii) As a result of the late general asset account election in Example 1, the $2 million of the natural gas transmission property that J  replaced during Year 1 is in a general asset account. Pursuant to § 1.168(i)-1(e)(2), J  does not recognize a loss upon the disposition of that $2 million of property and continues to depreciate that property on its Federal income tax return for Year 1 and subsequent taxable years.   
     
(iii) Because J  did not recognize a loss upon the disposition of that $2 million of property, the cost of $3.5 million for replacing a part of the natural gas transmission property during Year 1 is not a per se capital expenditure under section 5.05(1)(g) or (h) of this revenue procedure. Accordingly, for its Federal income tax return for Year 1, J  must apply the NGSH Method to all amounts incurred in Year 1 that are subject to the NGSH Method, including the $ 3.5 million in replacement costs. Also, J  must make general asset account elections to include in general asset accounts all costs capitalized under the NGSH Method in Year 1.   
     
(c) Example 3. (i) I  is a local natural gas distribution company. Before Year 1, I  owned and placed in service gas distribution property at a cost of $120 million before any dispositions or additions. Before Year 1, I  replaced parts of such property that had an original cost of $10 million and incurred $12 mil-lion for the cost of such replacements. On its Federal income tax returns before Year 1, I  recognized losses upon the dispositions of that $10 million of property and deducted $12 million for the cost of the replacements under § 162(a). During Year 1, I  replaced a part of the natural gas distribution property that had an original cost of $2 million and incurred $3 mil-lion for the cost of such replacements. On its Federal income tax return for Year 1, I  recognized a loss upon the disposition of the $2 million of replaced property, and deducted $3 million for the cost of the replacements under § 162(a). I  files a Form 3115 with its Federal income tax return for Year 2 to change its methods of accounting for its linear and non-linear property to use the NGSH Method.   
     
(ii) Because I  filed its method change in Year 2, the special rule for certain per se capital expenditures under section 5.08(3)(a) of this revenue procedure does not apply to taxable years ending before the taxpayer's first taxable year for which the taxpayer changes. Accordingly, the per se capital expenditure rules in section 5.05(1)(g) and (h) of this revenue procedure apply to the replacement cost of $12 million that I  deducted under § 162(a) on its Federal income tax returns before Year 1, and to the replacement cost of $3 million that I  deducted under § 162(a) on its Federal income tax return for Year 1. Therefore, the total cost of $15 million for these replacements is a per se capital expenditure, and must be capitalized, under the NGSH Method.   
     
(iii) At the beginning of Year 2, I  owns natural gas distribution property at a cost of $123 million ($120 million - $10 million + $12 million - $2 mil-lion + $3 million). Because Year 2 is I 's second taxable year ending after May 1, 2023, under section 5.08(2)(a)(i) of this revenue procedure, I  must make a late general asset account election on its Form 3115 to include in general asset accounts all of the $123 million of natural gas distribution property that I  owns at the beginning of Year 2. In addition, for its Federal income tax return for Year 2, I  must apply the NGSH Method to all amounts paid or incurred in Year 2 that are subject to the NGSH Method, and I  must make general asset account elections to include in general asset accounts all costs capitalized under the NGSH Method in Year 2.   
     
(d) Example 4. (i) H  is a local natural gas distribution company. Before Year 4, H  owned and placed in service natural gas distribution property at a cost of $150 million before any dispositions or additions. Before Year 4, H  replaced parts of such property that had an original cost of $30 million and incurred $45 million for the cost of such replacements. On its Federal income tax returns before Year 4, H  recognized losses upon the dispositions of that $30 million of property and capitalized $45 million for the cost of the replacements under § 263(a). H  files a Form 3115 with its Federal income tax return for Year 4 to change its methods of accounting for its linear and non-linear property to use the NGSH Method.   
     
(ii) At the beginning of Year 4, H  owns natural gas distribution property at a cost of $165 million ($150 million - $30 million + $45 million). Because Year 4 is H 's fourth taxable year ending after May 1, 2023, under section 5.08(2)(a)(iii) of this revenue procedure, H  must make a late general asset account election on its Form 3115 to include in general asset accounts all of the $165 million of natural gas distribution property that H  owns at the beginning of Year 4. Pursuant to section 5.08(3)(b)(i) of this revenue procedure, H  is not eligible to use any of the NGSH Method rules provided in sections 5.02, 5.03, 5.04, 5.05, 5.06, and 5.07 of this revenue procedure for any natural gas transmission and distribution property expenditures paid or incurred prior to Year 4. However, for its Federal income tax return for Year 4, H  must apply the NGSH Method to all amounts paid or incurred in Year 4 that are subject to the NGSH Method, and H  must make general asset account elections to include in general asset accounts all costs capitalized under the NGSH Method in Year 4..09 Class life asset depreciation range system (CLADR) percentage repair allowance exclusion.    A taxpayer that changes its treatment of natural gas transmission and distribution property expenditures to use the NGSH Method may not elect the class life asset depreciation range system repair allowance under §    1.167(a)-11(d)(2) in any taxable year that the taxpayer uses the NGSH Method. In addition, for any taxable year in which the § 1.167(a)-11(d)(2) repair allowance election was made, the NGSH Method may not be applied to change the taxpayer's treatment of property to which the taxpayer elected to apply the repair allowance under § 1.167(a)-11(d)(2)..10 Applicability of § 263A. Amounts paid or incurred to which the taxpayer applies the NGSH Method are not capitalized separately under § 263A(a)(1)(B) and (b)(1) as direct or indirect costs of producing gas transmission and distribution property. However, a taxpayer that produces natural gas or acquires natural gas for resale in its trade or business must capitalize under §    263A direct and allocable indirect costs of producing or acquiring such property or any other property subject to § 263A. See  §§ 1.263A-2 and 1.263A-3..11 Statistical sampling.    In applying the NGSH Method, statistical sampling may be used by following the guidance provided in Rev.Proc. 2011-42, 2011-37 I.R.B. 318.   
     
SECTION 6. CHANGE IN METHOD OF ACCOUNTING.01 In general.    A change to the safe harbor method for linear property and/or a change to the safe harbor method for non-linear property under this revenue procedure is a change in method of accounting to which the provisions of §§ 446 and 481, and the corresponding regulations, apply. However, section 6.04 of this revenue procedure allows certain taxpayers to choose to change to these methods of accounting on a cut-off basis. A taxpayer that wants to change to the methods of accounting described in this revenue procedure must, if eligible, use the automatic change procedures in Rev.Proc. 2015-13, 2015-5 I.R.B. 419, as clarified and modified by Rev.Proc. 2015-33, 2015-24 I.R.B. 1067, and as modified by Rev.Proc. 2021-34, 2021-35 I.R.B. 337, by Rev.Proc. 2021-26, 2021-22 I.R.B. 1163, by Rev.Proc. 2017-59, 2017-48 I.R.B. 543, and by section 17.02(b) and (c) of Rev.Proc. 2016-1, 2016-1 I.R.B. 1..02 Statistical sampling.    A taxpayer changing to the NGSH Method may use statistical sampling in determining the § 481(a) adjustment amount attributable to any single taxable year by following the guidance provided in Rev.Proc. 2011-42..03 Extrapolation.    A taxpayer changing to the NGSH Method may use the extrapolation methodology provided in Appendix B of this revenue procedure (Appendix B) in determining the § 481(a) adjustment amount, if the taxpayer is within the scope of section 1.02 of Appendix B. Extrapolation methodologies not permitted in Appendix B are not permitted under the NGSH Method..04 Optional cut-off basis for first 3 taxable years.   
     
(1) Availability of change on a cut-off basis. A taxpayer that changes to the safe harbor method for linear property for the taxpayer's first, second, or third taxable year ending after May 1, 2023, may choose to change to this method of accounting on a cut-off basis. See  section 2.07 of Rev.Proc. 2015-13. A taxpayer that chooses to change to the safe harbor method for linear property on a cut-off basis under this section 6.04, and also changes to the safe harbor method for non-linear property for the taxpayer's first, second, or third taxable year ending after May 1, 2023, also must change to the safe harbor method for non-linear property on a cut-off basis, regardless of the year of this change. A taxpayer that changes to the safe harbor method for linear property for the taxpayer's first, second, or third taxable year ending after May 1, 2013, and does not make this change on a cut-off basis is not permitted to change to the safe harbor method for non-linear property on a cut-off basis.   
     
(2) Effect of change on a cut-off basis. A taxpayer that chooses to change to the NGSH Method on a cut-off basis is not eligible to use the NGSH Method rules under sections 5.02, 5.03, 5.04, 5.05, 5.06, and 5.07 of this revenue procedure for any linear property costs and non-linear property costs paid or incurred prior to the year of change, but must make the late general asset account election for the property described in section 5.08(2)(a)(ii) of this revenue procedure. A §    481(a) adjustment is neither required nor permitted for the change to the NGSH Method on a cut-off basis. Further, a taxpayer that chooses to make this change on a cut-off basis under this section 6.04 does not receive audit protection under section 8.01 of Rev.Proc. 2015-13 in connection with this change. See  section 8.02(2) of Rev.Proc 2015-13..05 Automatic change.    Rev.Proc. 2022-14 is modified to add new section 3.12, to read as follows:   
     
3.12 Natural gas transmission and distribution property method of accounting under Rev.Proc. 2023-15.   
     
(1) Description of change.   
     
(a) Applicability. This change applies to a taxpayer that is within the scope of Rev.Proc. 2023-15 and wants to change its treatment of natural gas transmission and distribution property costs to use the natural gas transmission and distribution property safe harbor method of accounting (NGSH Method) described in Rev.Proc. 2023-15. Specifically, this change applies to a taxpayer that wants to change to "the safe harbor method for linear property" or "the safe harbor method for non-linear property" and other applicable rules in accordance with Rev.Proc. 2023-15, including the making of a late general asset account election as required under section 5.08(2) of Rev.Proc. 2023-15. This change also applies to a taxpayer that previously changed to the safe harbor method for linear property and wants to change to the safe harbor method for non-linear property for a subsequent taxable year.   
     
(b) Inapplicability. This change does not apply to the making of a late general asset account election other than in accordance with section 5.08(2) of Rev.Proc. 2023-15.   
     
(2) Certain eligibility rules temporarily inapplicable.   
     
(a) In general. The eligibility rules in section 5.01(1)(d) and (f) of Rev.Proc. 2015-13 do not apply to a taxpayer that changes to the NGSH Method provided in Rev.Proc. 2023-15 for its first, second, or third taxable year ending after May 1, 2023.   
     
(b) Concurrent automatic change.   
     
(i) If a taxpayer makes both a change under this section 3.12 and a change under section 6.12(3)(b) and/or section 6.15 of this revenue procedure for linear property and/or non-linear property for its first, second, or third taxable year ending after May 1, 2023, on a single Form 3115 for the same asset for the same year of change in accordance with section 3.12(6)(b) of this revenue procedure, the eligibility rules in section 5.01(1)(d) and (f) of Rev.Proc. 2015-13 do not apply to the taxpayer for these changes.   
     
(ii) If a taxpayer makes both a change under this section 3.12 and a change under section 11.08, 12.01, 12.02, 12.08, and/or 12.12 of this revenue procedure, as applicable, for its linear property or non-linear property costs in its first, second, or third taxable year ending after May 1, 2023, on a single Form 3115 for the same year of change in accordance with section 3.12(6) of this revenue procedure, the eligibility rules in section 5.01(1)(d) and (f) of Rev.Proc. 2015-13 do not apply to the taxpayer for these changes.   
     
(3) Manner of making change.   
     
(a) Late general asset account election.   
     
(i) The late general asset account election change described in section 5.08(2) of Rev.Proc. 2023-15 is made using a modified cut-off method under which the unadjusted depreciable basis and the depreciation reserve of the asset as of the beginning of the year of change are accounted for using the proposed method of accounting. The late general asset account election change requires each general asset account to include a beginning balance for both the unadjusted depreciable basis and the depreciation reserve. The beginning balance for the unadjusted depreciable basis of each general asset account is equal to the sum of the unadjusted depreciable basis as of the beginning of the year of change for all assets included in that general asset account. The beginning balance of the depreciation reserve of each general asset account is equal to the sum of the greater of the depreciation allowed or allowable as of the beginning of the year of change for all assets included in that general asset account.   
     
(ii) For the late general asset account election change described in section 5.08(2) of Rev.Proc. 2023-15, the taxpayer must attach to its Form 3115 a statement providing that the taxpayer agrees to the following additional terms and conditions:   
     
(A) The taxpayer consents to, and agrees to apply, all the provisions of § 1.168(i)-1 to the assets that are subject to the election specified in section 5.08(2) of Rev.Proc. 2023-15; and   
     
(B) Except as provided in § 1.168(i)-1(c)(1)(ii)(A), (e)(3), (g), or (h), the election made by the taxpayer under section 5.08(2) of Rev.Proc. 2023-15 is irrevocable and will be binding on the taxpayer for computing taxable income for the year of change and for all subsequent taxable years with respect to the assets that are subject to this election.   
     
(b) Cut-off basis for certain changes. Except for changes to make a late general asset account election described in section 3.12(3)(a) of this revenue procedure, a change to the NGSH Method described in Rev.Proc. 2023-15 is made on a cut-off basis and applies only to natural gas transmission and distribution property costs paid or incurred beginning in or after the year of change if-   
     
(i) Sections 5.08(2)(a)(ii) and 6.04 of Rev.Proc. 2023-15 apply (the taxpayer changes to the NGSH Method described in Rev.Proc. 2023-15 for the first, second, or third taxable year ending after May 1, 2023, on a cut-off basis); or   
     
(ii) Section 5.08(2)(a)(iii) of Rev.Proc. 2023-15 applies (the taxpayer changes to the NGSH Method described in Rev.Proc. 2023-15 for the fourth taxable year ending after May 1, 2023, or for any subsequent taxable year).   
     
(4) Section 481(a) adjustment.   
     
(a) In general. Except as provided in section 3.12(3)(b) of this revenue procedure, a taxpayer changing its methods of accounting under this section 3.12 must take the entire net § 481(a) adjustment into account, whether positive or negative, in computing taxable income for the year of change in the manner provided in section 7.03 of Rev.Proc. 2015-13. The entire net § 481(a) adjustment includes all aspects of the NGSH Method described in Rev.Proc. 2023-15, including a change to the methods of accounting permitted under § 1.168(i)-1 pursuant to section 5.08(2) of Rev.Proc. 2023-15. However, a § 481(a) adjustment is neither required nor permitted for the late general asset account election described in section 5.08(2) of Rev.Proc. 2023-15. Further, a § 481(a) adjustment is neither required nor permitted if the taxpayer chooses to change to the NGSH Method on a cut-off basis under section 6.04 of Rev.Proc. 2023-15 or if the taxpayer changes to this method during the time described in section 5.08(2)(a)(iii) of Rev.Proc. 2023-15.   
     
(b) Repair allowance property. A taxpayer changing its method of accounting under this section 3.12 must not include in the §    481(a) adjustment any amount attributable to property for which the taxpayer elected to apply the repair allowance under §    1.167(a)-11(d)(2) for any taxable year in which the repair allowance election was made.   
     
(c) Statistical sampling. A taxpayer changing to the NGSH Method under this section 3.12 may use statistical sampling in determining the § 481(a) adjustment amount attributable to any single taxable year by following the guidance provided in Rev.Proc. 2011-42, 2011-37 I.R.B. 318.   
     
(d) Extrapolation. A taxpayer changing to the NGSH Method under this section 3.12 may use the extrapolation methodology provided in Appendix B to Rev.Proc. 2023-15 (Appendix B) in determining the § 481(a) adjustment amount if the taxpayer is within the scope of section 1.02 of Appendix B. Extrapolation methodologies not permitted in Appendix B are not permitted under the NGSH Method.   
     
(5) No audit protection for certain taxpayers. If a taxpayer chooses to change to the NGSH Method described in Rev.Proc. 2023-15 on a cut-off basis as permitted under section 6.04 of Rev.Proc. 2023-15 or is required to change on a cut-off basis under section 5.08(3)(b)(i) of Rev.Proc. 2023-15, the taxpayer does not receive audit protection under section 8.01 of Rev.Proc. 2015-13 in connection with this change.   
     
(6) Concurrent automatic changes.   
     
(a) A taxpayer making changes under this section 3.12 for more than one asset for the same year of change must file a single Form 3115 for all such assets. The single Form 3115 must provide a single net §    481(a) adjustment for all such changes.   
     
(b) A taxpayer making changes under this section 3.12 and changes under section 6.12(3)(b) and/or section 6.15 of this revenue procedure for linear property or non-linear property costs for the same year of change must file a single Form 3115 for all changes and must enter the designated automatic accounting method change numbers for all changes on the appropriate line on the Form 3115. See section 6.03(1)(b) of Rev.Proc. 2015-13 for information on making concurrent changes.   
     
(c) A taxpayer making changes under this section 3.12 and also making a coordinating change to its linear property or non-linear property costs under section 11.08, 12.01, 12.02, 12.08, and/or 12.12 of this revenue procedure, as applicable, must file a single Form 3115 for the same year of change for all these changes, provided that the taxpayer is not prohibited from filing an automatic change under the eligibility rules under section 5 of Rev.Proc. 2015-13. For changes required to be filed on a single Form 3115 under this section, the taxpayer must enter the designated automatic accounting method change numbers for all changes on the appropriate line on the Form 3115. See section 6.03(1)(b) of Rev.Proc. 2015-13 for information on making concurrent changes.   
     
(d) A taxpayer that changes to a method of accounting under this section 3.12 for taxable years ending after the third taxable year ending after May 1, 2023 and is also required to change its method of accounting to properly capitalize its linear property or non-linear property costs under § 263(a) and/or § 263A under section 5.08(3)(b)(ii) of Rev.Proc. 2023-15, must file a single Form 3115 for the same year of change for all these changes, provided that the taxpayer is not prohibited from filing an automatic change under the eligibility rules set out in section 5 of Rev.Proc. 2015-13, 2015-5 I.R.B. 419. For changes required to be filed on a single Form 3115 under this paragraph, the taxpayer must enter the designated automatic accounting method change numbers for all changes on the appropriate line on the Form 3115. See section 6.03(1)(b) of Rev.Proc. 2015-13 for information on making concurrent changes.   
     
(7) Examples. The following examples illustrate this section 3.12. In each example, it is assumed that the taxpayer (a) is a C corporation, on an accrual method of accounting and using a calendar taxable year, (b) is within the scope of Rev.Proc. 2023-15, (c) placed in service natural gas transmission property or distribution property that is described in section 4 of Rev.Proc. 2023-15 and is MACRS property, (d) did not make a general asset account election for any natural gas transmission property or distribution property placed in service by the taxpayer in any taxable year before the first taxable year that the taxpayer uses the NGSH Method, (e) is changing its methods of accounting for both linear property and non-linear property under the NGSH Method for the same taxable year, and (f) is not changing to the NGSH Method on a cut-off basis under section 6.04 of Rev.Proc. 2023-15. Unless otherwise stated, it also is assumed that (a) the cost of the replacements before Year 1 were not capitalized under § 263(a), (b) the cost of the replacements before Year 1 would not have been capitalized if the taxpayer used the NGSH Method provided under sections 5.02, 5.03, 5.04, 5.06, and 5.07 of Rev.Proc. 2023-15 for such prior taxable years, and (c) the taxpayer's natural gas transmission and distribution property expenditures are not per se capital expenditures under section 5.05(1)(a)-(f), (i), or (j) of Rev.Proc. 2023-15. Further, it is assumed that § 1.168(i)-1(e)(3) (special rules for certain dispositions of assets in general asset accounts) does not apply for the first taxable year that the taxpayer uses the NGSH Method. Moreover, for purposes of these examples, "Year 1" refers to the taxpayer's first taxable year ending after May 1, 2023, "Year 2" refers to the taxpayer's second taxable year ending after May 1, 2023, and "Year 4" refers to the taxpayer's fourth taxable year ending after May 1, 2023.   
     
(a) Example 1. (i) X  is a local natural gas distribution company. Before Year 1, X  owned and placed in service natural gas distribution property at a cost of $120 million before any dispositions or additions. Before Year 1, X  replaced parts of such property that had an original cost of $10 million and incurred $12 million for the cost of such replacements. On its Federal income tax returns before Year 1, X  recognized losses upon the dispositions of that $10 million of property, capitalized $12 million for the cost of the replacements of that property under § 263(a), and deducted depreciation of $800,000 on such $12 million. X  files a Form 3115 with its Federal income tax return for Year 1 to change its methods of accounting to use the NGSH Method described in Rev.Proc. 2023-15.   
     
(ii) Because Year 1 is X 's first taxable year ending after May 1, 2023, section 5.08(2)(a)(i) and (3)(a) of Rev.Proc. 2023-15 apply. Pursuant to section 5.08(3)(a) of Rev.Proc. 2023-15, the per se capital expenditure rules in section 5.05(1)(g) and (h) of Rev.Proc. 2023-15 do not apply to the replacement cost of $12 million that X  capitalized under § 263(a) on its Federal income tax returns before Year 1. Accordingly, this $12 million cost of the replacements is not treated as a per se capital expenditure under the NGSH Method. Therefore, at the beginning of Year 1, X  is treated under Rev.Proc. 2023-15 as owning natural gas distribution property at a cost of $110 million ($120 million - $10 million). Under section 5.08(2)(a)(i) of Rev.Proc. 2023-15, X  must make a late general asset account election on its Form 3115 to include in general asset accounts all of the $110 million of natural gas distribution property that X  owns at the beginning of Year 1. These general asset accounts also must include the total depreciation allowed or allowable before the beginning of Year 1 for such property as the beginning balances of the depreciation reserves. The late general asset account election change is made on a modified cut-off method and, therefore, a §    481(a) adjustment is neither required nor permitted for the late general asset account election change.   
     
(iii) On its Form 3115 to change to the NGSH Method provided under Rev.Proc. 2023-15, the net negative §    481(a) adjustment for this change is $11,200,000 (deduction of $12 million for the cost of the replacements before Year 1 less depreciation of $800,000 for such replacement assets before Year 1) and is deducted in computing X 's taxable income for Year 1.   
     
(b) Example 2. (i) The facts are the same as in Example 1, except that X  files a Form 3115 with its Federal income tax return for Year 2 to change its method of accounting to use the NGSH Method described in Rev.Proc. 2023-15, and, before Year 2, X  deducted depreciation of $1,000,000 on the replacement cost of $12 million.   
     
(ii) Because X  filed its method change in Year 2, the special rule under section 5.08(3)(a) of Rev.Proc. 2023-15 does not apply to the replacement cost of $12 million that X  capitalized under § 263(a) on its Federal income tax returns before Year 1. Accordingly, section 5.05(1)(g) and (h) of Rev.Proc.  2023-15 apply to the replacement cost of $12 million that X  capitalized on its Federal income tax returns before Year 2. The total cost of $12 million for this replacement is a per se capital expenditure, and must be capitalized, under the NGSH Method.   
     
(iii) At the beginning of Year 2, X  is treated under the NGSH Method as owning natural gas distribution property at a cost of $122 million ($120 million - $10 million + $12 million). Under section 5.08(2)(a)(i) of Rev.Proc.  2023-15, X  must make a late general asset account election on its Form 3115 to include in general asset accounts all of the $122 million of natural gas distribution property that X  owns at the beginning of Year 2. These general asset accounts also must include the total depreciation allowed or allowable before the beginning of Year 2 for such property as the beginning balances of the depreciation reserves. The late general asset account election change is made on a modified cut-off method and, therefore, a § 481(a) adjustment is neither required nor permitted for the late general asset account election.   
     
(iv) On its Form 3115 to change to the NGSH Method under Rev.Proc. 2023-15, the net § 481(a) adjustment for this change is zero. Under its present method of accounting and under the NGSH Method (proposed method of accounting), X  properly capitalized the $12 million for the cost of the replacements before Year 1 and claimed depreciation for such replacement assets before Year 2.   
     
(c) Example 3. (i) Y  is a local natural gas distribution company. Before Year 1, Y  owned and placed in service natural gas distribution property at a cost of $120 million before any dispositions or additions. Before Year 1, Y  replaced parts of such property that had an original cost of $10 million, and incurred $12 million for the cost of such replacements. On its Federal income tax returns before Year 1, Y  recognized losses upon the dispositions of that $10 million of property, and deducted $12 million for the cost of the replacements of such property under § 162(a). During Year 1, Y  replaced a part of the natural gas distribution property that had an original cost of $2 million and incurred $3 million for the cost of such replacements. If Y  had capitalized the $15 million for the cost of the replacements, the total depreciation allowed or allowable for these assets would have been $1 million before Year 2. On its Federal income tax return for Year 1, Y  recognized a loss upon the disposition of that $2 million of property, and deducted $3 million for the cost of the replacements under § 162(a). Y  files a Form 3115 with its Federal income tax return for Year 2 to change its method of accounting to use the NGSH Method described in Rev.Proc. 2023-15.   
     
(ii) Because Y  filed its method change for Year 2, section 5.08(2)(a)(i) of Rev.Proc.  2023-15 applies to this change. However, the special rule under section 5.08(3)(a) of Rev.Proc. 2023-15 would apply only if Y  had filed its method change for Year 1. Accordingly, section 5.05(1)(g) and (h) of Rev.Proc. 2023-15 apply to the replacement cost of $12 million that Y  deducted under § 162(a) on its Federal income tax returns before Year 1, and to the replacement cost of $3 million that Y  deducted under § 162(a) on its Federal income tax return for Year 1. Therefore, the total cost of $15 million for these replacements is a per se capital expenditure, and must be capitalized, under the NGSH Method.   
     
(iii) At the beginning of Year 2, Y  is treated under Rev.Proc. 2023-15 as owning natural gas distribution property at a cost of $123 million ($120 million - $10 million + $12 million - $2 million + $3 million). Under section 5.08(2)(a)(i) of Rev.Proc. 2023-15, Y  must make a late general asset account election on its Form 3115 to include in general asset accounts all of the $123 million of natural gas distribution property that Y  owns at the beginning of Year 2. These general asset accounts also must include the total depreciation allowed or allowable before the beginning of Year 2 for such property as the beginning balances of the depreciation reserves. The late general asset account election change is made on a modified cut-off method and, therefore, a § 481(a) adjustment is neither required nor permitted for the late general asset account election.   
     
(iv) On its Form 3115 to change to the NGSH Method of Rev.Proc. 2023-15, the net positive § 481(a) adjustment for this change is $14 million ($15 million for the cost of the replacements before Year 2 less depreciation allowed or allowable of $1 million for such replacement assets before Year 2) and is taken into account in computing Y 's income in the manner provided in section 3.12(4)(a) of this revenue procedure.   
     
(d) Example 4. (i) Z  is a local natural gas distribution company. Before Year 4, Z  owned and placed in service natural gas distribution property at a cost of $150 million before any dispositions or additions. Before Year 4, Z  replaced parts of such property that had an original cost of $30 million and incurred $45 million for the cost of such replacements. On its Federal income tax returns before Year 4, Z  recognized losses upon the dispositions of that $30 million of property, capitalized $45 million for the cost of the replacements under §    263(a), and deducted depreciation of $15 million on such $45 million. Z  files a Form 3115 with its Federal income tax return for Year 4 to change its method of accounting to use the NGSH Method described in Rev.Proc. 2023-15. Assume Z  is eligible to file Form 3115 for Year 4 under the automatic change procedures in Rev.Proc. 2015-13.   
     
(ii) At the beginning of Year 4, Z  owns natural gas distribution property at a cost of $165 million ($150 million - $30 million + $45 million). Because Year 4 is Z 's fourth taxable year ending after May 1, 2023, sections 5.08(2)(a)(iii) and 5.08(3)(b) of Rev.Proc. 2023-15 apply. Accordingly, under section 5.08(2)(a)(iii) of Rev.Proc. 2023-15, Z  must make a late general asset account election on its Form 3115 to include in general asset accounts all of the $165 million of natural gas distribution property that Z  owns at the beginning of Year 4. These general asset accounts also must include the total depreciation allowed or allowable before the beginning of Year 4 for such property as the beginning balances of the depreciation reserves. The late general asset account election change is made using a modified cut-off method and, therefore, a §    481(a) adjustment is neither permitted nor required for the late general asset account election.   
     
(iii) Because sections 5.08(2)(a)(iii) and 5.08(3)(b) of Rev.Proc. 2023-15 apply, Z 's change to the NGSH Method described in Rev.Proc. 2023-15, applies only to natural gas transmission and distribution property expenditures paid or incurred by Z  beginning in Year 4 and is made on a cut-off basis. Therefore, a §    481(a) adjustment is neither required nor permitted for the change to the NGSH Method described in Rev.Proc. 2023-15.   
     
(e) Example 5. (i) The facts are the same as in Example 4  except that, on its Federal income tax returns before Year 4, Z  improperly deducted $45 million for the cost of the replacements under § 162(a). Such $45 million of replacement costs should have been capitalized under § 263(a). If Z  had capitalized the $45 million for the cost of the replacements, the total depreciation allowed or allowable for such assets would have been $15 million before Year 4.   
     
(ii) Because Year 4 is Z 's fourth taxable year ending after May 1, 2023, sections 5.08(2)(a)(iii) and 5.08(3)(b) of Rev.Proc. 2023-15 apply. Pursuant to section 5.08(3)(b) of Rev.Proc. 2023-15, Z  must also change its method of accounting to capitalize under § 263(a) the $45 million for the cost of the replacements incurred before Year 4. The net positive § 481(a) adjustment for this coordinating change is $30 million ($45 million for the cost of the replacements before Year 4 less depreciation allowed or allowable of $15 million for such replacement assets before Year 4). Z  takes this net positive § 481(a) adjustment of $30 million into account in computing Z 's taxable income in the manner provided in section 3.12(4)(a) of this revenue procedure.   
     
(iii) Z  owns natural gas distribution property at a cost of $165 million ($150 million - $30 million + $45 million) at the beginning of Year 4. Accordingly, Z  must make a late general asset account election on its Form 3115 to include in general asset accounts all of the $165 million of natural gas distribution property that Z  owns at the beginning of Year 4. These general asset accounts also must include the total depreciation allowed or allowable before the beginning of Year 4 for such property as the beginning balances of the depreciation reserves. The late general asset account election change is made using a modified cut-off method and, therefore, a § 481(a) adjustment is neither permitted nor required for the late general asset account election.   
     
(iv) Because sections 5.08(2)(a)(iii) and 5.08(3)(b) of Rev.Proc. 2023-15 apply, Z 's change to the NGSH Method provided under sections 5.02, 5.03, 5.04, 5.06, and 5.07 of Rev.Proc. 2023-15, applies only to natural gas transmission and distribution property expenditures paid or incurred by Z  beginning in Year 4 and is made on a cut-off basis. Therefore, a §    481(a) adjustment is neither required nor permitted for the change to the NGSH Method described in Rev.Proc. 2023-15.   
     
(v) Pursuant to section 3.12(6)(c) and section 5.08(3)(b) of Rev.Proc. 2023-15 the change to capitalize the replacement costs of $45 million, the late general asset account election change, and the change to use the NGSH Method provided under Rev.Proc. 2023-15 must be included on the same Form 3115 filed by Z  for Year 4.   
     
(8) Designated automatic accounting method change number. The designated automatic accounting method change number for a change to the methods of accounting under this section 3.12 is "269."   
     
(9) Contact information. For further information regarding a change under this section, contact Hyowon Lee or Merrill Feldstein at (202) 317-5100 (not a toll-free call).   
     
SECTION 7. EFFECT ON OTHER DOCUMENTS.01 Section 3.12 of Rev.Proc. 2022-14 is modified to include the accounting method changes in this revenue procedure..02 Rev.Proc. 2011-42 is amplified.   
     
SECTION 8. EFFECTIVE DATE   
     
This revenue procedure is effective for taxable years ending after May 1, 2023.   
     
SECTION 9. PAPERWORK REDUCTION ACT   
     
The collection of information contained in this revenue procedure has been submitted to the Office of Management and Budget for review under OMB control number 1545-0123 in accordance with the Paperwork Reduction Act (44 U.S.C. 3507(d)). An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. The collection of information in this revenue procedure is in section 6. This information is necessary and will be used to determine whether the taxpayer properly changed to a permitted method of accounting. The collections of information are required for the taxpayer to obtain consent to change its method of accounting.   
     
SECTION 10. DRAFTING INFORMATION   
     
The principal authors of this revenue procedure are Natasha Mulleneaux and Merrill Feldstein of the Office of Associate Chief Counsel (Income Tax and Accounting). For further information regarding this revenue procedure, contact Hyowon Lee or Merrill Feldstein at 202-317-5100 (not a toll-free number).   
     
APPENDIX A--UNIT OF PROPERTY AND MAJOR COMPONENT DEFINITIONS FOR NON-LINEAR PROPERTY   
     
SECTION 1. INTRODUCTION.01 In general.    This Appendix A lists the units of property and major components for non-linear natural gas transmission and distribution property to which the taxpayer applies the non-linear safe harbor method. See  section 5.04 of this revenue procedure. The units of property and major components are listed for compressor stations, gas storage facilities, and measuring and regulating stations, including city gate stations. Not all the identified units of property are necessarily present at a given location; for example, an above-ground compressed natural gas storage facility will not have liquefaction equipment or a well. Each meter and regulator is a separate unit of property, wherever located. If a unit of property has major components, all the major components are identified. The treatment of the costs of non-linear property that are not specifically identified in this Appendix A (for example, tools, fixtures, furniture, computer equipment, and other miscellaneous equipment) are excluded from this revenue procedure and are determined under §§ 263(a), 263A, and other applicable authority..02 Instrumentation and controls.    In general, instrumentation and controls are a major component of the unit of property they monitor or control. However, all the on-site instrumentation and controls for each compressor station, gas storage facility, or measuring and regulating station that are not associated with a particular unit of property are a single unit of non-linear property. As used in this revenue procedure, the term "instrumentation and controls" does not include assets that are treated as separate units of property (for example, meters and regulators)..03 Scope.    This Appendix A does not apply to determine the units of property of non-linear property or the major components of these units of property if the taxpayer does not use the safe harbor method for non-linear property.   
     
SECTION 2. Units of non-linear property.01 Compressor station property.    At a compressor station, the units of non-linear property are the following:   
     
(1) Each compressor, including prime mover.   
     
(2) Each meter.   
     
(3) Each regulator.   
     
(4) Each tank.   
     
(5) Each flaring or incinerating system, including stack.   
     
(6) All the lines at the station, including header, pipe, coatings, fittings, valves, and cathodic protection.   
     
(7) All the gas detection equipment at the station.   
     
(8) All the equipment to maintain pipeline gas quality at the station, including the following major components:   
     
(a) Each scrubber.   
     
(b) Each filter separator.   
     
(c) Each separator.   
     
(d) Each dehydrator (also referred to as a dryer).   
     
(e) Each chromatograph.   
     
(f) Each continuous gas sampler.   
     
(g) Each water vapor monitor.   
     
(h) Each sulfur removal apparatus.   
     
(i) Each cooler.   
     
(j) Each heater.   
     
(9) All the electric supply equipment at the station, including the following major components:   
     
(a) Each generator, including motor.   
     
(b) Each set of batteries and charger.   
     
(c) Each transformer.   
     
(d) Each power supply (for example, a variable frequency drive).   
     
(e) All other electric supply devices, including switchgear.   
     
(10) All the odorizing equipment at the station, including the following major components:   
     
(a) All the equipment to inject an odorant or other additive into the gas stream.   
     
(b) Each tank for storing odorant or other additive.   
     
(11) All the onsite instrumentation and control equipment at the station that is not a major component of a specific unit of non-linear property.   
     
(12) Each structure, including pad, walls, and roof, housing compressors and related equipment.   
     
(13) Each additional structure, including pad, walls, and roof.   
     
(14) All fencing, walls, enclosures, and miscellaneous structures or land improvements that are not capitalized to the land surrounding a compressor station and any miscellaneous pads.   
     
(15) Each parcel of land and each easement or other right to land..02 Gas storage facility property.    At a gas storage facility, the units of property are the following:   
     
(1) Each tank.   
     
(2) Each well, including the following major components:   
     
(a) The wellhead.   
     
(b) The casing.   
     
(3) Each compressor, including prime mover.   
     
(4) Each meter.   
     
(5) Each regulator.   
     
(6) Each flaring or incinerating system, including stack.   
     
(7) All the lines at the facility, including header, pipe, coatings, fittings, valves, and cathodic protection.   
     
(8) All the equipment to maintain pipeline quality gas at the facility, including the following major components:   
     
(a) Each scrubber.   
     
(b) Each filter separator.   
     
(c) Each separator.   
     
(d) Each dehydrator (also referred to as a dryer).   
     
(e) Each chromatograph.   
     
(f) Each continuous gas sampler.   
     
(g) Each water vapor monitor.   
     
(h) Each sulfur removal apparatus.   
     
(i) Each cooler.   
     
(j) Each heater.   
     
(9) All the odorizing equipment at the facility, including the following major components:   
     
(a) All the equipment to inject an odorant or other additive into the gas stream.   
     
(b) Each tank for storing odorant or other additive.   
     
(10) All the liquefaction equipment at the facility, including the following major components:   
     
(a) Each cold box.   
     
(b) Each heat exchanger.   
     
(c) Each condenser.   
     
(d) Each vaporizing unit (also referred to as a vaporizer).   
   
(11) All the onsite instrumentation and control equipment at the facility that is not a major component of a specific unit of non-linear property.   
     
(12) Each structure, including pad, walls, and roof, housing compressors and related equipment.   
     
(13) Each additional structure, including pad, walls, and roof.   
     
(14) All the fencing, walls, enclosures, and/or miscellaneous structures surrounding the facility and any miscellaneous pads.   
     
(15) Each parcel of land and each easement or other right to land..03 Measuring and regulating station property.    At a measuring and regulating station, including a city gate station, the units of non-linear property are the following:   
     
(1) Each meter.   
     
(2) Each regulator.   
     
(3) All the lines at the station, including header, pipe, coatings, fittings, valves, and cathodic protection.   
     
(4) All the equipment to maintain pipeline quality gas at the station, including the following major components:   
     
(a) Each scrubber.   
     
(b) Each filter separator.   
     
(c) Each separator.   
     
(d) Each dehydrator (also referred to as a dryer).   
     
(e) Each chromatograph.   
     
(f) Each continuous gas sampler.   
     
(g) Each water vapor monitor.   
     
(h) Each sulfur removal apparatus.   
     
(i) Each heater.   
     
(5) All the odorizing equipment at the station, including the following major components:   
     
(a) All the equipment to inject an odorant or other additive into the gas stream.   
     
(b) Each tank for storing odorant or other additive.   
     
(6) All the onsite instrumentation and control equipment at the facility that is not a major component of a specific unit of non-linear property.   
     
(7) Each structure, including pad, walls, and roof.   
     
(8) All the fencing, walls, enclosures, and miscellaneous structures surrounding the station and any miscellaneous pads.   
     
(9) Each parcel of land and each easement or other right to land..04 Meters and regulators.    Each meter and each regulator not described in sections 2.01 through 2.03 of this Appendix A, including a meter or regulator located at a customer's premises, is a separate unit of non-linear property.   
     
APPENDIX B--EXTRAPOLATION GUIDANCE   
     
SECTION 1. INTRODUCTION.01 In general.    This Appendix B provides an extrapolation methodology that an eligible taxpayer may use in connection with a change to apply the NGSH Method. The extrapolation methodology described in this Appendix B provides the exclusive extrapolation methodology that is permitted under the NGSH Method for determining the amount of a § 481(a) adjustment..02 Scope.    This Appendix B does not apply to a change to apply the NGSH Method if the taxpayer does not have a minimum of three representative years within the testing period as described in section 2.02(1) of this Appendix B.   
     
SECTION 2. EXTRAPOLATION METHODOLOGY.01 Application.    A taxpayer making a change to apply the NGSH Method may use the extrapolation procedures provided in this Appendix B to determine the § 481(a) adjustment resulting from the change in method of accounting for the safe harbor method for linear property and the safe harbor method for non-linear property, if applicable. A taxpayer may choose to use this extrapolation procedure for its change to the safe harbor method for linear property, for its change to the safe harbor for non-linear property, or for both changes. The extrapolation procedures are performed separately for the safe harbor method for linear property and the safe harbor method for non-linear property to determine the respective § 481(a) adjustment. Generally, the taxpayer first applies the method to a testing period of recent, representative years and derives an average repair deduction under the method of accounting as a percentage of total capital additions for financial accounting purposes. This percentage, adjusted by a reduction percentage that varies based on time, is then applied to the adjusted capital additions for financial accounting purposes for prior years for which extrapolation is used to derive a deemed § 481(a) adjustment amount for each year. These extrapolated § 481(a) adjustment amounts are then combined with the actual adjustment amounts for years in which the §   481(a) adjustment is calculated in the normal manner to arrive at the total §    481(a) adjustment attributable to the change in method of accounting..02 Calculation methodology.    In order to determine the amount of the § 481(a) adjustment for a prior year to which extrapolation is applied, the following calculation methodology must be used:   
     
(1) Testing period. First, a testing period is determined as follows:   
     
(a) In general. The taxpayer must use as the testing period a minimum of three consecutive taxable years (testing years), except as described in section 2.02(1)(b)(ii) of this Appendix B. Generally, the final year of the testing period is the taxable year preceding the year of change. Alternatively, a taxpayer may choose the year of change as the final year of the testing period.   
     
(b) Representative years required. The testing years must be representative of all years included in the § 481(a) adjustment.   
     
(i) In determining whether a year is representative, a taxpayer must take into account restructuring transactions, including acquisitions and dispositions as well as any other events that resulted in significant capital changes.   
     
(ii) If one of the taxable years in the testing period described in section 2.02(1)(a) of this Appendix B is not representative, the taxpayer must exclude data from the non-representative year from the testing period and use data from the fourth most recent taxable year to establish a testing period (with such fourth most recent taxable year being a testing year). If the fourth most recent taxable year is not representative either, the taxpayer may not use an extrapolation methodology for determining the amount of a § 481(a) adjustment attributable to its change to the NGSH Method under this revenue procedure.   
     
(c) Additional years. Under the extrapolation calculation methodology, if the taxpayer has sufficient data to calculate the repair deduction percentage for more than three years, the taxpayer may include those years in the testing period. The additional testing years must be consecutive years that immediately precede the original three-year testing period, except that a year that is not representative, as described in section 2.02(1)(b) of this Appendix B, must be excluded. A taxpayer may not use, as an additional testing year, a year that is separated from the rest of the testing period by more than one non-representative year.   
     
(2) Repair deduction percentage. Second, a repair deduction percentage for each year for which extrapolation is used (extrapolation year) is computed as follows, using data from the testing period.   
     
(a) Repair deductions during the testing period under the proposed method. For each testing year, the amount of repair expenses that would be allowable as deductions under the NGSH Method, before taking into account book-tax basis adjustments, is determined.   
     
(b) Tentative repair deduction percentage. The sum of the repair expenses allowable as deductions for all testing years in the testing period, as determined under section 2.02(2)(a) of this Appendix B, is then divided by the sum of all capital additions during the testing period. For this purpose, a taxpayer must use capital additions for financial statement purposes (book capital additions). The resulting ratio represents the average percentage of capitalized additions that are properly treated as repair expenses allowable as deductions under the NGSH Method (tentative repair deduction percentage), before taking into account book-tax basis adjustments.   
     
(c) Repair deduction percentage for an extrapolation year. The tentative repair deduction percentage is then multiplied by a reduction percentage for each extrapolation year. For each extrapolation year, the reduction percentage is determined by using the formula (1 - (0.10*( X / Y ))), where X  equals the number of years the extrapolation year precedes the final year of the testing period and Y  equals the total number of taxable years in the testing period. The reduction percentage for an extrapolation year multiplied by the tentative repair deduction percentage equals the repair deduction percentage for the extrapolation year.   
     
(3) Extrapolation year tentative repair deduction amount. Third, a tentative repair deduction amount under the proposed method is calculated for each extrapolation year.   
     
(a) The repair deduction amount for an extrapolation year is calculated by multiplying the repair deduction percentage for the extrapolation year (determined in section 2.02(2) of this Appendix B) by the book capital additions for the extrapolation year.   
     
(b) In determining the repair deduction amount for an extrapolation year, a taxpayer must account for any book-tax basis adjustments for property placed in service in the extrapolation year. Book-tax basis adjustments for property placed in service in the extrapolation year may be accounted for by multiplying the tentative repair deduction amount for an extrapolation year by the taxpayer's book-to-tax adjustment percentage for the extrapolation year. Tax adjustments that must be accounted for include, but are not limited to, the following types of adjustments:   
     
(i) adjustments resulting from a change in accounting method permitted under Rev.Proc. 2000-7, 2000-1 C.B. 712, involving the treatment of the costs incurred in removing retired assets;   
     
(ii) adjustments resulting from a change in the treatment of capitalized amounts determined under § 263A, including reductions for additional mixed service costs allocated to inventory and adjustments to account for changes to interest capitalization amounts;   
     
(iii) adjustments arising from casualty loss deductions recognized under § 165; and   
     
(iv) adjustments resulting from research and experimental expenditures deducted under § 174.   
     
(4) Repair allowance adjustment and repair deduction amount. Fourth, for each extrapolation year in which the repair allowance election under §    1.167(a)-11(d)(2) (ADR repair allowance) was made, the tentative repair deduction amount must be reduced by the cost of repairs to natural gas transmission property or natural gas distribution property attributable to ADR repair allowance property. To determine the reduction where a prior ADR repair allowance election was made for the natural gas transmission property or natural gas distribution property, taxpayers must use a method comparable to the method actually used to allocate qualified repair expenditures to repair allowance property for that year. For example, if in applying § 1.167(a)-11(d)(2) for the 1997 taxable year a taxpayer determined that 73 percent of its 1997 qualified repair expenditures for natural gas transmission and natural gas distribution property were attributable to repair allowance property, then that same percentage (73 percent) must be applied to determine the reduction to the repair deduction amount otherwise calculated under section 2.02(3) of this Appendix B. The amount determined after reducing the tentative repair deduction amount by the cost of repairs attributable to CLADR repair allowance property is the repair deduction amount for the extrapolation year.   
     
(5) Tentative extrapolation year § 481(a) adjustment amount. Fifth, the tentative §    481(a) adjustment amount for each extrapolation year is determined. The tentative §    481(a) adjustment for each extrapolation year is calculated by subtracting the repair deduction amount for that year, as determined under sections 2.02(1) through 2.02(4) of this Appendix B, from the amount of repair expenses the taxpayer deducted for that year under its prior method of accounting, including § 481(a) adjustments resulting from any prior change in method of accounting. The difference, whether positive or negative, is the tentative §    481(a) adjustment amount for the extrapolation year.   
     
(6) Extrapolation year §      481(a) adjustment amount. Sixth, the tentative § 481(a) adjustment amount for each extrapolation year must be adjusted to account for any differences in depreciation, credits, or any other cumulative differences in deductions between the extrapolation year and the year of change resulting from the taxpayer's proposed method of accounting. For instance, if under the proposed method a taxpayer's repair deduction for an extrapolation year would be tentatively increased by $1,000, such that the unadjusted basis of the property placed in service would be correspondingly decreased by $1,000, the $1,000 tentative repair deduction increase for the extrapolation year must be reduced by the portion of the $1,000 in unadjusted basis that the taxpayer had recovered prior to the year of change.   
     
(7) Total §      481(a) adjustment. Finally, the total §    481(a) adjustment attributable to the change to the taxpayer's proposed method of accounting is determined. The total § 481(a) adjustment for the year of change is calculated by combining the § 481(a) adjustment amounts for all extrapolation years, as described in this section 2.02 of this Appendix B, with the adjustment amounts, after taking into account book-tax basis adjustments, for years determined under §    481(a) in the normal manner..03 Example.    In 2023, W, a calendar year taxpayer, changes its method of accounting to the NGSH Method. W  uses the extrapolation methodology provided in section 2 of this Appendix B to determine the amount of its § 481(a) adjustment attributable to taxable years 2003 through 2019.   
     
Following the general rule in section 2.02(1) of this Appendix B, W  uses as its testing period 2020, 2021, and 2022, the three consecutive taxable years ending with 2022, the year preceding the year of change. Assume that each of 2020, 2021, and 2022 are representative of all years included in W 's § 481(a) adjustment.   
     
 W   's book capital additions for 2020, 2021, and 2022 are $3,000, $3,000, and $4,000, respectively, for a total of $10,000. Of these amounts, the portions that are properly treated as repair expenses allowable as deductions resulting from the application of W 's proposed method of accounting for 2020, 2021, and 2022, before taking into account book-tax basis adjustments, are $300, $400, and $300, respectively, for a total of $1,000.   
     
For its 2014 extrapolation year, W 's book capital additions were $3,333. W 's book-to-tax adjustment percentage for 2014 is 90 percent. In 2013, W  elected to apply the ADR repair allowance under § 1.167(a)-11(d)(2), which applied to 25 percent of W 's natural gas transmission and natural gas distribution property. Under W 's prior method of accounting (prior to application of the NGSH Method), W  deducted $150 in repair expenses in 2014.   
     
 W    determines its § 481(a) adjustment for 2014 as follows:   
     
  Step 1. W  determines that it will use taxable years 2020, 2021, and 2022 as the testing years in its testing period.   
     
  Step 2. W  calculates its repair deduction percentage for each extrapolation year. First, a tentative repair deduction percentage is calculated using data from the testing period (taxable years 2020, 2021, and 2022). Book capital additions that are properly treated as repair expenses allowable as deductions resulting from the application of the proposed method of accounting, before taking into account book-tax basis adjustments, for 2020, 2021, and 2022, the testing years that comprise the testing period, equal $1,000 ($300 + $400 + $300). Total book capital additions for the testing period are $10,000 ($3,000 + $3,000 + $4,000). W 's tentative repair deduction percentage is 10 percent ($1,000 / $10,000).   
     
Next, W  calculates the reduction percentage for each extrapolation year using the formula (1 - (0.10 * ( X/Y ))), where X  equals the number of years the extrapolation year precedes 2022, the final year of the testing period, and Y  equals 3, the number of years in the testing period (2020-2022). The reduction percentage for each extrapolation year is calculated as follows:   
   
       
   
Finally, W  multiplies the tentative repair deduction percentage for each extrapolation year by the reduction percentage for each extrapolation year to calculate the repair deduction percentage for each extrapolation year. Accordingly, for 2014, W 's repair deduction percentage is 7.33 percent (10 percent X 73.33 percent = 7.33 percent).   
     
  Step 3. Next, W  calculates a tentative repair deduction amount for each extrapolation year. For its 2014 extrapolation year, W  multiplies its book capital additions for 2014 ($3,333) by its repair deduction percentage (7.33 percent), resulting in an initial tentative repair deduction amount of $244. Next, W  accounts for any book-tax basis adjustments for property placed in service in 2014 by multiplying the initial tentative repair deduction amount ($244) for 2014 by W 's book-to-tax adjustment percentage for 2014 (90 percent), resulting in a tentative repair deduction amount of $220.   
     
  Step 4. W  must reduce its tentative repair deduction amount for 2014 to exclude repairs attributable to natural gas transmission property and natural gas distribution property for which W  elected to apply the ADR repair allowance. In 2014, W  determined that 25 percent of its 2014 qualified repair expenditures for natural gas transmission and natural gas distribution property were attributable to repair allowance property. Therefore, W  reduces the repair deduction amount for 2014 ($220) by 25 percent ($55), yielding a repair deduction amount for 2014 of $165.   
     
  Step 5. W  determines its tentative § 481(a) adjustment amount for 2014. W  subtracts the adjusted gross repair deduction amount for 2014 ($165) from the amount of repair expenses W  deducted for 2014 under its prior method of accounting (as adjusted for purposes of computing any prior §   481(a) adjustment) ($150). Therefore, W 's §    481(a) adjustment amount for 2014 is negative $15.    
     
  Step 6. To determine its § 481(a) adjustment amount for 2014, W  must account for its decreased depreciation deductions resulting from the additional $15 of repair expenditures allowable as deductions under the proposed method of accounting. Assuming that the additional $15 of repair expenditures allowable as deductions for 2014 results in a $4.50 of reduction in cumulative depreciation expense through January 1, 2023, the beginning of the year of change, that is attributable to the assets placed in service in 2014, W 's § 481(a) adjustment amount for the increased repair deductions that would have been permitted in 2014 under the proposed method of accounting is negative $10.50 (-$15.00 + $4.50).   
     
  Step 7. To determine its total §    481(a) adjustment, W  combines the adjustments attributable to its extrapolation years 2003 through 2019, computed using the extrapolation method in this Appendix B (as described above for 2014), with the § 481(a) adjustments attributable to 2020 through 2022, determined using the actual data from those years and taking into account book-tax basis adjustments. W  must take the entire § 481(a) adjustment (whether positive or negative) into account in 2023, W 's year of change.