rp-23-15.pdf

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Part III

Administrative, Procedural, and Miscellaneous

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 ...................................................................................................... 3

SECTION 2. BACKGROUND ............................................................................................. 3
SECTION 3. SCOPE ........................................................................................................... 9
.01 In general..............................................................................................9
.02 Application to entities.............................................................................9
.03 Exclusions...........................................................................................9
SECTION 4. DEFINITIONS.............................................................................10

SECTION 5. NATURAL GAS TRANSMISSION AND DISTRIBUTION PROPERTY
SAFE HARBOR METHOD OF ACCOUNTING ................................................................ 16

.01 In general.......................................... ...................................................16
.02 Safe harbor method for linear property—application to transmission property....18
.03 Safe harbor method for linear property—application to distribution property......19

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.04 Safe harbor method for non-linear property—application to transmission and
distribution property....... .............................................................................21
.05 Per se capital expenditures.....................................................................22
.06 Aggregation requirements... ....................................................................31
.07 Safe harbor method for linear property—rules for distribution service line costs..44
.08 General asset accounts and transition rules................................................52
.09 Class life asset depreciation range system (CLADR) percentage repair allowance
exclusion...................................................................................................62
.10 Applicability of § 263A........ ....................................................................63
.11 Statistical sampling... .............................................................................63
SECTION 6. CHANGE IN METHOD OF ACCOUNTING.......................................63

.01 In general.............................................................................................63
.02 Statistical sampling... ..............................................................................64
.03 Extrapolation........................................................................................64
.04 Optional cut-off basis for first 3 taxable years..... ..........................................64
.05 Automatic change............................................................................ ......65
SECTION 7. EFFECT ON OTHER DOCUMENTS .......................................................... 79

SECTION 8. EFFECTIVE DATE ...................................................................................... 80
SECTION 9. PAPERWORK REDUCTION ACT .............................................................. 80
SECTION 10. DRAFTING INFORMATION ...................................................................... 80
APPENDIX A—UNIT OF PROPERTY AND MAJOR COMPONENT DEFINITIONS FOR
NON-LINEAR PROPERTY ............................................................................................... 81

SECTION 1. INTRODUCTION ......................................................................................... 81
.01 In general.............................................................................................81
.02 Instrumentation and controls.....................................................................81
.03 Scope.. ................................................................................................82
SECTION 2. UNITS OF NON-LINEAR PROPERTY ....................................................... 82

.01 Compressor station property.....................................................................82
.02 Gas storage facility property.....................................................................84
.03 Measuring and regulating station property......... ..........................................85
.04 Meters and regulators........ .....................................................................87
APPENDIX B—EXTRAPOLATION GUIDANCE .............................................................. 88

SECTION 1. INTRODUCTION ......................................................................................... 88

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.01 In general...... .......................................................................................88
.02 Scope..................................................................................................88
SECTION 2. EXTRAPOLATION METHODOLOGY ........................................................ 88

.01 Application............................................................................................88
.02 Calculation methodology..........................................................................89
.03 Example....... .....................................................................................94

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.
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

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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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

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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

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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

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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

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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 [date of
publication of this revenue procedure in the IRB], 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

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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

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(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.

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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,

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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

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(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

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this revenue procedure.
.17 Instrumentation and controls
. “Instrumentation and controls” mean 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

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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.

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.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

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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

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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

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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

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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

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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.

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(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

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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

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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

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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

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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.

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(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

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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

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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

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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

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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:

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(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;

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(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.

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(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

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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

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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

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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
un
der 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

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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
un
der 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

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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

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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

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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.

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(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

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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

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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

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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

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(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 unidentified 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

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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

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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):
Total
unidentified
distribution
service line
costs (Step 1
)

X
Capitalized distribution main
replacement costs not associated with
identified distribution service line costs
(Step 3
)
-----------------------------------------------------
Total distribution main replacement
costs not associated with identified
distribution service line costs
(Step 2
)

=
Capitalized
unidentified
distribution
service line
costs (Step 5
)

(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,
Capitalization ratio (Step 4)

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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 i
ncurs 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

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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

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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

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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.

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(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

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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

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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

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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

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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-o ff 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

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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
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. The following examples do not
address the treatment of depreciation or the requirement or computation of the § 481(a)

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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 service 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,
t
he 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

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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 di
d 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 million 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 million for
the cost of such replacements. On its Federal income tax return for Year 1, I

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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 f
iled 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 ow
ns natural gas distribution property at a cost
of $123 million ($120 million-$10 million+$12 million-$2 million+$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.

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(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 ow
ns 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

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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

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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

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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

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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

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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
bases 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:

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(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

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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

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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

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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

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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.

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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.
P
roc. 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.

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(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 i
s 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

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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 f
iled 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) 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

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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 i
s 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,
t
he 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

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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 ow
ns 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 1. 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 c
hange 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

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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 o
wns 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

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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
t
he 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.

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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 call).

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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).

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.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.

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(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.

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.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.

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(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.

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(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.

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.04 Meters and regulators
. Each meter and each regulator not described in section
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.

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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

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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

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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

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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

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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

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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

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$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.
F
ollowing 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

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$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 det
ermines 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 c
alculates 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

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is calculated as follows:
Extrapolation
Year
Reduction Percentage
Calculation
(Step A)
Reduction Percentage Calculation
(Step B)
2019 0.10 * (3/3) = 0.10 1 – 0.10 = 0.90 = 90.0%
2018 0.10 * (4/3) = 0.133 1 – 0.133 = 0.867 = 86.7%
2017 0.10 * (5/3) = 0.167 1 – 0.167 = 0.833 = 83.3%
2016 0.10 * (6/3) = 0.20 1 – 0.20 = 0.80 = 80.0%
2015 0.10 * (7/3) = 0.233 1 – 0.233 = 0.767 = 76.7%
2014 0.10 * (8/3) = 0.267 1 – 0.267 = 0.733 = 73.3%
2013 0.10 * (9/3) = 0.30 1 – 0.30 = 0.70 = 70.0%
2012 0.10 * (10/3) = 0.333 1 – 0.333 = 0.667 = 66.7%
2011 0.10 * (11/3) = 0.367 1 – 0.367 = 0.633 = 63.3%
2010 0.10 * (12/3) = 0.40 1 – 0.40 = 0.60 = 60.0%
2009 0.10 * (13/3) = 0.433 1 – 0.433 = 0.567 = 56.7%
2008 0.10 * (14/3) = 0.467 1 – 0.467 = 0.533 = 53.3%
2007 0.10 * (15/3) = 0.50 1 – .50 = 0.50 = 50.0%
2006 0.10 * (16/3) = 0.533 1 – 0.533 = 0.467 = 46.7%
2005 0.10 * (17/3) = 0.567 1 – 0.567 = 0.433 = 43.3%
2004 0.10 * (18/3) = 0.60 1 – 0.60 = 0.40 = 40.0%
2003 0.10 * (19/3) = 0.633 1 – 0.633 = 0.367 = 36.7%

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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,

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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.