Internal Revenue Bulletin 2023-18 (PDF rendition): IRS Revenue Procedures

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Bulletin No. 2023–18
May 1, 2023
HIGHLIGHTS
OF THIS ISSUE
These synopses are intended only as aids to the reader in
identifying the subject matter covered. They may not be
relied upon as authoritative interpretations.
ADMINISTRATIVE
Announcement 2023-13, page 833.
The Office of Professional Responsibility (OPR) announces
recent disciplinary sanctions involving attorneys, certified
public accountants, enrolled agents, enrolled actuaries,
enrolled retirement plan agents, and appraisers. These indi-
viduals are subject to the regulations governing practice
before the Internal Revenue Service (IRS), which are set out in
Title 31, Code of Federal Regulations, Part 10, and which are
published in pamphlet form as Treasury Department Circular
No. 230. The regulations prescribe the duties and restric-
tions relating to such practice and prescribe the disciplinary
sanctions for violating the regulations.
Rev. Proc. 2023-15, page 806.
This revenue procedure provides a safe harbor method of
accounting that taxpayers may use to determine whether
expenses to repair, maintain, replace, or improve natural
gas transmission and distribution property must be capital-
ized. To apply this safe harbor method, a taxpayer must first
classify its natural gas transmission and distribution prop-
erty as either linear property (for example, pipe, fittings,
and valves) or non-linear property (for example, compres-
sors, regulators, and meters). This revenue procedure then
provides methods of accounting for each type of property,
specifically, a safe harbor method used for the taxpayer’s
linear transmission and distribution property and an optional
safe harbor method that the taxpayer may choose to use
for its non-linear transmission and distribution property. The
revenue procedure also provides procedures for obtaining
automatic consent to change to the safe harbor method for
linear property and the safe harbor method for non-linear
property.
EMPLOYEE PLANS
Notice 2023-33, page 803.
This notice sets forth updates on the corporate bond monthly
yield curve, the corresponding spot segment rates for April
2023 used under § 417(e)(3)(D), the 24-month average
segment rates applicable for April 2023, and the 30-year
Treasury rates, as reflected by the application of § 430(h)
(2)(C)(iv).
INCOME TAX
Rev. Rul. 2023-8, page 801.
This revenue ruling obsoletes Revenue Ruling 58-74, 1958-1
C.B. 148, relating to the deductibility of research or exper-
imental expenditures for prior taxable years to which the
expense method is applicable, because there are insufficient
facts in Revenue Ruling 58-74 to properly analyze whether
the taxpayer’s failure to deduct certain research or exper-
imental expenditures, when it deducted other research or
experimental expenditures, constituted a method of account-
ing or an error.
Finding Lists begin on page ii.

The IRS Mission
Provide America’s taxpayers top-quality service by helping
them understand and meet their tax responsibilities and
enforce the law with integrity and fairness to all.
Introduction
The Internal Revenue Bulletin is the authoritative instrument
of the Commissioner of Internal Revenue for announcing offi-
cial rulings and procedures of the Internal Revenue Service
and for publishing Treasury Decisions, Executive Orders, Tax
Conventions, legislation, court decisions, and other items of
general interest. It is published weekly.
It is the policy of the Service to publish in the Bulletin all
substantive rulings necessary to promote a uniform appli-
cation of the tax laws, including all rulings that supersede,
revoke, modify, or amend any of those previously published
in the Bulletin. All published rulings apply retroactively unless
otherwise indicated. Procedures relating solely to matters
of internal management are not published; however, state-
ments of internal practices and procedures that affect the
rights and duties of taxpayers are published.
Revenue rulings represent the conclusions of the Service
on the application of the law to the pivotal facts stated in
the revenue ruling. In those based on positions taken in rul-
ings to taxpayers or technical advice to Service field offices,
identifying details and information of a confidential nature are
deleted to prevent unwarranted invasions of privacy and to
comply with statutory requirements.
Rulings and procedures reported in the Bulletin do not have the
force and effect of Treasury Department Regulations, but they
may be used as precedents. Unpublished rulings will not be
relied on, used, or cited as precedents by Service personnel in
the disposition of other cases. In applying published rulings and
procedures, the effect of subsequent legislation, regulations,
court decisions, rulings, and procedures must be considered,
and Service personnel and others concerned are cautioned
against reaching the same conclusions in other cases unless
the facts and circumstances are substantially the same.
The Bulletin is divided into four parts as follows:
Part I.—1986 Code.
This part includes rulings and decisions based on provisions
of the Internal Revenue Code of 1986.
Part II.—Treaties and Tax Legislation.
This part is divided into two subparts as follows: Subpart A,
Tax Conventions and Other Related Items, and Subpart B,
Legislation and Related Committee Reports.
Part III.—Administrative, Procedural, and Miscellaneous.
To the extent practicable, pertinent cross references to these
subjects are contained in the other Parts and Subparts. Also
included in this part are Bank Secrecy Act Administrative
Rulings. Bank Secrecy Act Administrative Rulings are issued
by the Department of the Treasury’s Office of the Assistant
Secretary (Enforcement).
Part IV.—Items of General Interest.
This part includes notices of proposed rulemakings, disbar-
ment and suspension lists, and announcements.
The last Bulletin for each month includes a cumulative index
for the matters published during the preceding months. These
monthly indexes are cumulated on a semiannual basis, and are
published in the last Bulletin of each semiannual period.
The contents of this publication are not copyrighted and may be reprinted freely. A citation of the Internal Revenue Bulletin as the source would be appropriate.
May 1, 2023 Bulletin No. 2023–18

Part I
Section 174.—Amortization
of Research and
Experimental Expenditures
26 CFR 1.174-1: Research and experimental expen-
ditures; in general.
(Also §§ 446, 7805(b)(8); 1.174-3, 1.446-1,
301.7805-1).
Rev. Rul. 2023-8
This revenue ruling obsoletes Rev. Rul.
58-74, 1958-1 C.B. 148.
LAW AND ANALYSIS
Section 13206 of Public Law 115-97,
131 Stat. 2054 (Dec. 22, 2017), com-
monly referred to as the Tax Cuts and Jobs
Act (TCJA), amended § 174 of the Inter-
nal Revenue Code (Code) effective for
amounts paid or incurred in taxable years
beginning after December 31, 2021.
1
For amounts paid or incurred in taxable
years beginning on or before Decem-
ber 31, 2021, former § 174(a) permitted
a taxpayer to currently deduct research
or experimental expenditures that were
paid or incurred during the taxable year
in connection with its trade or business
(expense method). Alternatively, a tax-
payer could elect to defer and amortize
these expenditures under former § 174(b).
If expenditures were neither currently
deducted nor deferred and amortized, they
had to be charged to capital account. See
§ 1.174-1.
If the expense method was adopted for
amounts paid or incurred in taxable years
beginning on or before December 31,
2021, it had to be used for all qualifying
expenditures in the taxable year adopted
and for all subsequent years, unless the
Commissioner of Internal Revenue or the
Commissioner’s delegate (Commissioner)
consented to a different method for all
or part of the expenditures under former
§ 174(a)(3). See § 1.174-3(a). A tax-
payer on a different method could apply
for permission to change to the expense
method for all or part of the expenditures
by submitting a written application to
the Internal Revenue Service (IRS). See
§ 1.174-3 and section 7.01 of Rev. Proc.
2022-14, 2022-7 I.R.B. 502.
Rev. Rul. 58-74 provides that if a
taxpayer adopted the expense method
but failed to deduct expenses relating
to the cost of obtaining a patent or other
items of research or experimental expen-
ditures for prior taxable years to which
the expense method is applicable, the
taxpayer should file a claim for refund
or amended return to deduct additional
research or experimental expenditures in
the year or years when the expenditures
were paid or accrued. Rev. Rul. 58-74 fur-
ther provides that the additional research
or experimental expenditures cannot be
treated as deferred and amortized under
former § 174(b) or chargeable to capi-
tal account and subsequently amortized
or written off upon abandonment of the
project or projects because the Commis-
sioner’s consent to change a method of
accounting was not obtained. Accord-
ingly, the deduction for the additional
research or experimental expenditures
could be lost if the period of limitations
on claims for credit or refund under
§ 6511 has expired and amended returns
could not be timely filed.
Section 13206(a) of the TCJA amended
former § 174 to require research or exper-
imental expenditures (for amounts paid or
incurred in taxable years beginning after
December 31, 2021) to be charged to cap-
ital account and amortized ratably over
the five-year period (or the 15-year period
in the case of any specified research or
experimental expenditures which are
attributable to foreign research) begin-
ning with the midpoint of the taxable
year in which the specified research or
experimental expenditures were paid or
incurred. The rationale of the Department
of the Treasury (Treasury Department) and
the IRS for obsoleting Rev. Rul. 58-74 is
independent of the removal of the expense
method by the TCJA amendments to for-
mer § 174.
Pursuant to the authority provided
under § 301.7805-1 of the Procedure
and Administration Regulations, the
Treasury Department and the IRS period-
ically obsolete rulings that are no longer
determinative because: (1) the applicable
statutory provisions or regulations have
been changed or repealed; (2) the ruling
position is specifically covered by a stat-
ute, regulation, or subsequent published
position; or (3) the facts set forth no lon-
ger exist or are not sufficiently described
to permit clear application of the current
statute and regulations.
The Treasury Department and the IRS
are obsoleting Rev. Rul. 58-74 because
there are insufficient facts in the ruling to
properly analyze whether the taxpayer’s
failure to deduct certain research or exper-
imental expenditures, such as the cost of
obtaining a patent, when it deducted other
research or experimental expenditures,
constituted a method of accounting or an
error. For example, Rev. Rul. 58-74 does
not explain whether the taxpayer consis-
tently treated the costs of obtaining a patent
in determining its taxable income. See
Huffman v. Commissioner, 126 T.C. 322,
354 (2006), aff’d, 518 F.3d 357 (6th Cir.
2008) (“[I]t is the consistent treatment of
an item involving a question of timing that
establishes such treatment as a method of
accounting.”). Rev. Rul. 58-74 also fails to
describe the cause and extent of the devia-
tion in the treatment of certain research or
experimental expenditures that were not
deducted. See § 1.446-1(e)(2)(ii)(b).
Whether a change in accounting treat-
ment of amounts paid or incurred for
research or experimentation expenditures
constitutes a change in method of account-
ing or the correction of an error depends on
the specific facts of a particular situation.
If the facts demonstrate that a taxpayer has
a change in method of accounting, then
filing an amended return, refund claim, or
administrative adjustment request under
§ 6227 (AAR), as applicable, in reliance
upon Rev. Rul. 58-74 would conflict with
the statutory requirement that a taxpayer
must secure the consent of the Commis-
1
Unless otherwise specified, all “section” or “§” references are to sections of the Code or the Income Tax Regulations (26 CFR part 1) and references to “former § 174” are to § 174 as in
effect immediately prior to the effective date of the amendments made by § 13206 of the TCJA.
Bulletin No. 2023–18 801 May 1, 2023

sioner to change a method of accounting.
See § 446(e), former § 174(a)(3), § 1.174-
3(b), and § 1.174-4(b), as applicable,
for the taxable years in which former
§ 174 was in effect. In addition, filing an
amended return, refund claim, or AAR,
as applicable, in reliance upon Rev. Rul.
58-74 in such a case would be inconsistent
with the IRS’s position that a taxpayer may
not, without prior consent, retroactively
change from an erroneous to a permissible
method of accounting by filing amended
returns. See § 446(e); § 1.446-1(e)(2)(i);
Capital One Fin. Corp. v. Commissioner,
659 F.3d 316, 322-23 (4th Cir. 2011); Die-
bold Inc. v. United States, 891 F.2d 1579,
1583 (Fed. Cir. 1989), cert. denied, 498
U.S. 823 (1990). Lastly, filing an amended
return, refund claim, or AAR, as applica-
ble, in reliance upon Rev. Rul. 58-74 in
such a case would be inconsistent with
the automatic change procedure for a
taxpayer changing from treating research
or experimental expenditures under any
provision of the Code other than § 174 to
treating such expenditures under former
§ 174 and the regulations thereunder. See
section 7.01(2)(a)(iv) of Rev. Proc. 2022-
14. For these reasons, Rev. Rul. 58-74 is
no longer determinative.
EFFECT ON OTHER REVENUE
RULINGS
Rev. Rul. 58-74 is obsoleted.
PROSPECTIVE APPLICATION
Pursuant to § 7805(b), Rev. Rul. 58-74
is obsoleted as of July 31, 2023. The
obsoletion of Rev. Rul. 58-74 does not
affect the characterization of the costs
of obtaining a patent in § 1.174-2(a)(1).
Furthermore, the obsoletion of Rev. Rul.
58-74 does not affect the specific rules for
changing a method of accounting under
former § 174 and the regulations under
former § 174, including the requirement
that such change be implemented on a
cut-off basis. See former § 174(a)(3),
§ 1.174-3(b)(2), and § 1.174-4(a)(5).
A taxpayer may file a claim for refund,
amended return, or AAR, as applicable, in
reliance on Rev. Rul. 58-74 if the taxpayer
is (1) claiming a deduction for additional
research or experimental expenditures to
which the expense method under former
§ 174(a) is applicable for the taxable year
or years in which they were improperly
deferred or capitalized, (2) otherwise
using the expense method for such tax-
able year or years, and (3) timely filing the
claim for refund, amended return, or AAR
not later than July 31, 2023. The eligibil-
ity to file a claim for refund, an amended
return, or an AAR in reliance on Rev.
Rul. 58-74 does not imply that the IRS
will grant such claim for refund, amended
return, or AAR. The IRS will continue to
challenge the applicability of Rev. Rul.
58-74 to a particular claim for refund,
amended return, or AAR when appropri-
ate. For example, the IRS may challenge
the applicability of Rev. Rul. 58-74 when
the taxpayer’s facts in the amended return,
refund claim, or AAR are distinguishable
from Rev. Rul. 58-74, including where
the taxpayer failed to adopt the expense
method under former § 174(a).
DRAFTING INFORMATION
The principal author of this revenue
ruling is Bruce Chang of the Office of
Associate Chief Counsel (Income Tax
& Accounting). For further information
regarding this revenue ruling, contact Mr.
Chang at (202) 317-4870 (not a toll-free
number).

May 1, 2023 802 Bulletin No. 2023–18

Bulletin No. 2023–18 803 May 1, 2023
Part III
Update for Weighted
Average Interest Rates,
Yield Curves, and Segment
Rates
Notice 2023-33
This notice provides guidance on the
corporate bond monthly yield curve, the
corresponding spot segment rates used
under § 417(e)(3), and the 24-month aver-
age segment rates under § 430(h)(2) of the
Internal Revenue Code. In addition, this
notice provides guidance as to the inter-
est rate on 30-year Treasury securities
under § 417(e)(3)(A)(ii)(II) as in effect for
plan years beginning before 2008 and the
30-year Treasury weighted average rate
under § 431(c)(6)(E)(ii)(I).
YIELD CURVE AND SEGMENT
RATES
Section 430 specifies the minimum
funding requirements that apply to sin-
gle-employer plans (except for CSEC plans
under § 414(y)) pursuant to § 412. Section
430(h)(2) specifies the interest rates that
must be used to determine a plan’s target
normal cost and funding target. Under
this provision, present value is generally
determined using three 24-month average
interest rates (“segment rates”), each of
which applies to cash flows during speci-
fied periods. To the extent provided under
§ 430(h)(2)(C)(iv), these segment rates
are adjusted by the applicable percentage
of the 25-year average segment rates for
the period ending September 30 of the
year preceding the calendar year in which
the plan year begins.
1
However, an elec-
tion may be made under § 430(h)(2)(D)
(ii) to use the monthly yield curve in place
of the segment rates.
Notice 2007-81, 2007-44 I.R.B. 899,
provides guidelines for determining the
monthly corporate bond yield curve, and
the 24-month average corporate bond
segment rates used to compute the target
normal cost and the funding target. Con-
sistent with the methodology specified in
Notice 2007-81, the monthly corporate
bond yield curve derived from March 2023
data is in Table 2023-3 at the end of this
notice. The spot first, second, and third seg-
ment rates for the month of March 2023
are, respectively, 5.00, 5.20, and 5.15.
The 24-month average segment rates
determined under § 430(h)(2)(C)(i)
through (iii) must be adjusted pursuant
to § 430(h)(2)(C)(iv) to be within the
applicable minimum and maximum per-
centages of the corresponding 25-year
average segment rates. For this purpose,
any 25-year average segment rate that is
less than 5% is deemed to be 5%. The
25-year average segment rates for plan
years beginning in 2022 and 2023 were
published in Notice 2021-54, 2021-41
I.R.B. 457, and Notice 2022-40, 2022-40
I.R.B. 266, respectively. The applicable
minimum and maximum percentages are
95% and 105% for a plan year beginning
in 2022 or 2023.
24-MONTH AVERAGE CORPORATE
BOND SEGMENT RATES
The three 24-month average corporate
bond segment rates applicable for April
2023 without adjustment for the 25-year
average segment rate limits are as follows:
24-Month Average Segment Rates Without 25-Year Average Adjustment
Applicable Month First Segment Second Segment Third Segment
April 2023 2.68 3.93 4.12
The adjusted 24-month average seg-
ment rates set forth in the chart below
reflect § 430(h)(2)(C)(iv) of the Code. The
24-month averages applicable for April
2023, adjusted to be within the applicable
minimum and maximum percentages of
the corresponding 25-year average seg-
ment rates in accordance with § 430(h)(2)
(C)(iv) of the Code, are as follows:
Adjusted 24-Month Average Segment Rates
For Plan Years
Beginning InApplicable MonthFirst SegmentSecond SegmentThird Segment
2022April 20234.755.185.92
2023April 20234.755.005.74
30-YEAR TREASURY SECURITIES
INTEREST RATES
Section 431 specifies the mini-
mum funding requirements that apply
to multiemployer plans pursuant to
§ 412. Section 431(c)(6)(B) specifies
a minimum amount for the full-fund-
ing limitation described in § 431(c)(6)
(A), based on the plan’s current liabil-
ity. Section 431(c)(6)(E)(ii)(I) provides
that the interest rate used to calculate
current liability for this purpose must
be no more than 5 percent above and
no more than 10 percent below the
1
Pursuant to § 433(h)(3)(A), the third segment rate determined under § 430(h)(2)(C) is used to determine the current liability of a CSEC plan (which is used to calculate the minimum amount
of the full funding limitation under § 433(c)(7)(C)).

May 1, 2023 804 Bulletin No. 2023–18
weighted average of the rates of interest
on 30-year Treasury securities during
the four-year period ending on the last
day before the beginning of the plan
year. Notice 88-73, 1988-2 C.B. 383,
provides guidelines for determining the
weighted average interest rate. The rate
of interest on 30-year Treasury securi-
ties for March 2023 is 3.77 percent. The
Service determined this rate as the aver-
age of the daily determinations of yield
on the 30-year Treasury bond maturing
in February 2053. For plan years begin-
ning in April 2023, the weighted average
of the rates of interest on 30-year Trea-
sury securities and the permissible range
of rates used to calculate current liabil-
ity are as follows:
Treasury Weighted Average Rates
For Plan Years Beginning In30-Year Treasury Weighted AveragePermissible Range 90% to 105%
April 20232.572.32 to 2.70
MINIMUM PRESENT VALUE
SEGMENT RATES
In general, the applicable interest rates
under § 417(e)(3)(D) are segment rates
computed without regard to a 24-month
average. Notice 2007-81 provides guide-
lines for determining the minimum
present value segment rates. Pursuant to
that notice, the minimum present value
segment rates determined for March 2023
are as follows:
Minimum Present Value Segment Rates
Month First Segment Second Segment Third Segment
March 2023 5.00 5.20 5.15
DRAFTING INFORMATION
The principal author of this notice
is Tom Morgan of the Office of Associ-
ate Chief Counsel (Employee Benefits,
Exempt Organizations, and Employment
Taxes). However, other personnel from
the IRS participated in the development
of this guidance. For further information
regarding this notice, contact Mr. Morgan
at 202-317-6700 or Tony Montanaro at
626-927-1475 (not toll-free number).

Bulletin No. 2023–18 805 May 1, 2023
Table 2023-3
Monthly Yield Curve for March 2023
Derived from March 2023 Data
MaturityYieldMaturityYieldMaturityYieldMaturityYieldMaturityYield
0.55.2120.55.2540.55.1360.55.1080.55.08
1.05.1621.05.2441.05.1361.05.1081.05.08
1.55.1021.55.2441.55.1361.55.1081.55.08
2.05.0522.05.2342.05.1362.05.1082.05.08
2.54.9922.55.2342.55.1362.55.1082.55.08
3.04.9523.05.2243.05.1363.05.1083.05.08
3.54.9123.55.2243.55.1363.55.1083.55.08
4.04.8824.05.2144.05.1364.05.1084.05.08
4.54.8724.55.2144.55.1264.55.1084.55.08
5.04.8725.05.2045.05.1265.05.1085.05.08
5.54.8925.55.2045.55.1265.55.0985.55.08
6.04.9126.05.1946.05.1266.05.0986.05.08
6.5
4.9426.55.1946.55.1266.55.0986.55.08
7.04.9727.05.1947.05.1267.05.0987.05.08
7.55.0127.55.1847.55.1267.55.0987.55.08
8.05.0528.05.1848.05.1268.05.0988.05.08
8.55.0828.55.1848.55.1268.55.0988.55.08
9.05.1229.05.1749.05.1269.05.0989.05.08
9.55.1529.55.1749.55.1269.55.0989.55.08
10.05.1830.05.1750.05.1170.05.0990.05.08
10.55.2130.55.1750.55.1170.55.0990.55.08
11.05.2331.05.1751.05.1171.05.0991.05.08
11.55.2531.55.1651.55.1171.55.0991.55.08
12.05.2732.05.1652.05.1172.05.0992.05.08
12.55.2832.55.1652.55.1172.55.0992.55.08
13.05.2933.05.1653.0
5.1173.05.0993.05.08
13.55.3033.55.1653.55.1173.55.0993.55.08
14.05.3034.05.1554.05.1174.05.0994.05.08
14.55.3134.55.1554.55.1174.55.0994.55.08
15.05.3135.05.1555.05.1175.05.0995.05.08
15.55.3135.55.1555.55.1175.55.0995.55.08
16.05.3036.05.1556.05.1176.05.0996.05.07
16.55.3036.55.1456.55.1076.55.0996.55.07
17.05.2937.05.1457.05.1077.05.0997.05.07
17.55.2937.55.1457.55.1077.55.0997.55.07
18.05.2838.05.1458.05.1078.05.0898.05.07
18.55.2838.55.1458.55.1078.55.0898.55.07
19.05.2739.05.1459.05.1079.05.0899.05.07
19.55.2639.55.1459.55.1079.55.0899.5
5.07
20.05.2640.05.1460.05.1080.05.08100.05.07

May 1, 2023 806 Bulletin No. 2023–18
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 ..................................................................................807
SECTION 2. BACKGROUND ............................................................................807
SECTION 3. SCOPE ....................................................................................808
.01 In general ..........................................................................................808
.02 Application to entities ................................................................................809
.03 Exclusions .........................................................................................809
SECTION 4. DEFINITIONS ..............................................................................809
SECTION 5. NATURAL GAS TRANSMISSION AND DISTRIBUTION PROPERTY SAFE HARBOR
METHOD OF ACCOUNTING ................................................................810
.01 In general ..........................................................................................810
.02 Safe harbor method for linear property—application to transmission property ....................................811
.03 Safe harbor method for linear property—application to distribution property .....................................811
.04 Safe harbor method for non-linear property—application to transmission and distribution property ...................812
.05 Per se capital expenditures ............................................................................812
.06 Aggregation requirements... ...........................................................................814
.07 Safe harbor method for linear property—rules for distribution service line costs ..................................817
.08 General asset accounts and transition rules ................................................................819
.09 Class life asset depreciation range system (CLADR) percentage repair allowance exclusion .........................821
.10 Applicability of § 263A........ ..........................................................................821
.11 Statistical sampling ..................................................................................822
SECTION 6. CHANGE IN METHOD OF ACCOUNTING ....................................................822
.01 In general ..........................................................................................822
.02 Statistical sampling ..................................................................................822
.03 Extrapolation .......................................................................................822
.04 Optional cut-off basis for first 3 taxable years .............................................................822
.05 Automatic change ...................................................................................822
SECTION 7. EFFECT ON OTHER DOCUMENTS ..........................................................825
SECTION 8. EFFECTIVE DATE
..........................................................................825
SECTION 9. PAPERWORK REDUCTION ACT .............................................................825
SECTION 10. DRAFTING INFORMATION ................................................................826
APPENDIX A— UNIT OF PROPERTY AND MAJOR COMPONENT DEFINITIONS FOR
NON-LINEAR PROPERTY ................................................................827
SECTION 1. INTRODUCTION ...........................................................................827
.01 In general ..........................................................................................827
.02 Instrumentation and controls ...........................................................................827
.03 Scope .............................................................................................827

Bulletin No. 2023–18 807 May 1, 2023
SECTION 2. UNITS OF NON-LINEAR PROPERTY .........................................................827
.01 Compressor station property ...........................................................................827
.02 Gas storage facility property ...........................................................................827
.03 Measuring and regulating station property ................................................................828
.04 Meters and regulators ................................................................................828
APPENDIX B—EXTRAPOLATION GUIDANCE ...........................................................829
SECTION 1. INTRODUCTION ...........................................................................829
.01 In general ..........................................................................................829
.02 Scope .............................................................................................829
SECTION 2. EXTRAPOLATION METHODOLOGY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .829
.01 Application ........................................................................................829
.02 Calculation methodology .............................................................................829
.03 Example ...........................................................................................830
SECTION 1. PURPOSE
This revenue procedure provides a safe
harbor method of accounting that taxpay-
ers 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 tax-
payer 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 dis-
tribute natural gas pay or incur significant
expenditures to maintain, repair, replace,
and improve natural gas transmission
and distribution property. Generally,
whether these expenditures are allowable
as deductions under § 162 for repairs or
maintenance or must be capitalized under
§ 263(a) as improvements to property
depends on whether these expenditures
result in a betterment or restoration of the
property or adapt it to a new or different
use. See
§§ 1.162-4 and 1.263(a)-3(d).
Whether these expenditures are capital-
ized under § 263A depends, generally, on
whether these expenditures are properly
allocable to property produced by the
taxpayer. See § 1.263A-1(a)(3). Apply-
ing capitalization principles to natural
gas transmission and distribution prop-
erty can be particularly difficult, largely
because the property consists of a network
of interconnected assets. As a conse-
quence, there often exists uncertainty as to
whether certain costs to maintain, repair,
replace, and improve parts or components
of such interconnected property are capi-
tal expenditures or expenses allowable as
deductions.
.02 To reduce uncertainty and asso-
ciated 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 allow-
able 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 reve-
nue 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 tax-
payer 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, reg-
ulators, and meters). If a taxpayer chooses
to use the NGSH Method for its linear
property, the taxpayer (1) must use the
“safe harbor method for linear property”
(as defined under section 4.02 of this rev-
enue procedure) for all of the taxpayer’s
linear transmission and distribution prop-
erty and (2) may choose to apply the “safe
harbor method for non-linear property”
(as defined under section 4.03 of this rev-
enue 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 transmis-
sion 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 lin-
ear property provides different rules for
linear transmission property (generally,
linear property that transmits natural gas
from production facilities to local distri-
bution systems) and for linear distribution
property (generally, linear property that
distributes natural gas to local custom-
ers). For linear transmission property, the
safe harbor method for linear property
defines the appropriate units of transmis-
1
Unless otherwise specified, all “section” or “§” references are to sections of the Code or the Income Tax Regulations (26 CFR part 1).

May 1, 2023 808 Bulletin No. 2023–18
sion 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 lin-
ear distribution property, the safe harbor
method does not define units of property
but divides distribution property into
“distribution mains” and “distribution
service lines” and provides simplified
rules for determining whether the costs
of replacing distribution mains and the
costs of repairing, maintaining, replacing,
or improving distribution service lines
must be capitalized under §§ 263(a) and
263A. See sections 5.03 and 5.07 of this
revenue procedure. A taxpayer using the
safe harbor method for linear property is
required to use it for both its linear trans-
mission property and its linear distribution
property.
.05 The safe harbor method for non-lin-
ear property defines units of property and
major components of non-linear transmis-
sion 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-lin-
ear 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 prop-
erty. 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 tax-
payer must use this safe harbor method
for all its non-linear transmission and dis-
tribution property.
.06 This revenue procedure also pro-
vides “per se capitalization rules” that
apply to both linear and non-linear prop-
erty. 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 proce-
dure. 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 capital-
ization rules, a taxpayer using the NGSH
Method must capitalize the costs of:
(1) replacing all or part of property if the
taxpayer deducts a loss for the replaced
property (other than a casualty loss) or
takes the adjusted basis of the replaced
property into account in realizing gain or
loss resulting from a sale or exchange of
the replaced property; and (2) repairing
and replacing all or part of property for
which the taxpayer is required to take a
basis adjustment as a result of a casu-
alty 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 trans-
mission and distribution property often
involve dispositions of properties that
are replaced. These dispositions gener-
ally require taxpayers to recognize gain
or loss, or take a basis adjustment, thus
triggering the disposition/loss per se capi-
talization rules under the NGSH Method.
Accordingly, the NGSH Method would
not be useful without providing a mech-
anism to mitigate the effects of these
dispositions and the resulting application
of the disposition/loss per se capitaliza-
tion 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 sec-
tion 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 disposi-
tion 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 dispo-
sition/loss per se capitalization rules. The
use of general asset accounts also allows
a taxpayer to continue to depreciate this
property after its disposition.
In addition, to facilitate the transition
to the use of general asset accounts, this
revenue procedure requires a taxpayer
using the NGSH Method to make a late
general asset account election under
§§ 168(i)(4) and § 1.168(i)-1(l) for natural
gas transmission and distribution property
that the taxpayer previously placed in ser-
vice and owns at the beginning of its year
of change. See section 5.08(2) of this rev-
enue procedure. Moreover, to incentivize
taxpayers to use the NGSH method and
to encourage taxpayers to change to the
NGSH method for their first taxable year
ending after May 1, 2023, this revenue
procedure provides a special transition
rule. Under this rule, if a taxpayer changes
to the NGSH Method for its first taxable
year ending after May 1, 2023, the tax-
payer does not have to apply certain per
se capitalization rules to amounts paid or
incurred to replace or repair linear prop-
erty or non-linear property, as applicable,
in taxable years ending on or before May
1, 2023. See section 5.08(3)(a) of this rev-
enue procedure.
.08 The safe harbor method for lin-
ear 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 Com-
missioner to prescribe administrative
procedures setting forth the limitations,
terms, and conditions necessary to per-
mit a taxpayer to obtain consent to
change a method of accounting. Section
6.05 of this revenue procedure provides
the procedures by which a taxpayer may
obtain automatic consent for a change
in method of accounting to use the safe
harbor method for linear property and
the safe harbor method for non-linear
property.
SECTION 3. SCOPE
.01 In general. Only a taxpayer that
meets both of the requirements of section
3.01(1) and (2) of this revenue procedure
may choose to apply the NGSH Method.
(1) The taxpayer has a depreciable
interest in natural gas transmission or dis-

Bulletin No. 2023–18 809 May 1, 2023
tribution 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 deter-
mination 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 trans-
mission, distribution, control, or storage
of natural gas at a marine liquefied natural
gas terminal capable of shipping or receiv-
ing liquid natural gas for import or export;
(2) The costs of enclosures or buildings
suitable for occupation;
(3) The costs of non-linear prop-
erty 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 inspec-
tion gauges as defined in section 4.27 of
this revenue procedure; and
(5) The costs of cleaning pipeline
inspection gauges as defined in section
4.28 of this revenue procedure.
SECTION 4. DEFINITIONS
The following definitions apply solely
for purposes of this revenue procedure
(including its appendices):
.01 Natural gas transmission and dis-
tribution 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, collec-
tively, 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-lin-
ear 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 prop-
erty. “Natural gas transmission property”
means real and personal property that
is used to transport, control, and store
natural gas at any point between (1) a
gas processing plant or custody transfer
point and (2) a city gate station or other
delivery point, generally connecting to
a natural gas distribution system. Gas
production wells, gathering lines, and
processing plants are not included in this
definition.
.05 Natural gas distribution property.
“Natural gas distribution property” means
real and personal property that is used to
transport, control, and store natural gas at
any point between (1) a city gate station
or other custody transfer point generally
connecting to a transmission system,
and (2) the customer gas meter or other
delivery point to the customer. For this
purpose, “natural gas distribution prop-
erty” 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 prop-
erty” means all natural gas transmission
and distribution property except non-lin-
ear property. Examples of linear property
include pipes, valves, tunnels, casing, and
fittings.
.07 Non-linear property. “Non-linear
property” means all natural gas trans-
mission 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, liq-
uefaction 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, mainte-
nance, replacements, and/or improvements
to natural gas transmission or distribution
property.
.09 Blanket work order. “Blanket
work order” means a written document
that authorizes a project or projects over
a specific period of time, generally not
exceeding one year. A blanket work
order may include repairs, maintenance,
replacements, and/or improvements to
natural gas transmission or distribution
property.
.10 Replacement. “Replacement”
means the installation of property so that
existing property can be removed from
service, whether or not the existing prop-
erty 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 sep-
arate 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 natu-
ral 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 proce-
dure (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 dis-
tribution system begins; or
(6) a custody transfer point where the
gas is delivered to or from another party.
For example, a regulator located between

May 1, 2023 810 Bulletin No. 2023–18
another regulator and a compressor station
divides that section of linear transmis-
sion 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 stor-
age facilities or in transmission lines,
including but not limited to compressors,
instrumentation and controls, meters,
regulators, measuring equipment, odoriz-
ing 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 sta-
tion 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. “Measur-
ing 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 mea-
sures gas flow, as defined in section 4.23
of this revenue procedure.
.17 Instrumentation and controls.
“Instrumentation and controls” means the
analog and digital devices that measure,
monitor, or control the equipment at storage
facilities, compressor stations, and measur-
ing 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, instrumenta-
tion 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. “Dis-
tribution mains” means more than one
section of distribution main in a natural
gas distribution system.
.19 Distribution service line. “Distribu-
tion 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 trans-
mission 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 instru-
ment for measuring and indicating or
recording the flow of gas that has passed
through it.
.24 Regulator. “Regulator” means a
device that reduces the pressure in a gas
line and maintains the pressure within a
constant band.
.25 Well. “Well” means a cased bore
hole used for gas input or output for an
underground storage reservoir, including
a storage well.
.26 Equipment to maintain pipeline
quality gas. “Equipment to maintain
pipeline quality gas,” also known as
“purification equipment,” means equip-
ment 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, ero-
sion 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 clean-
ing pipelines by removing sedimentation
and build-up that can impede the flow of
gas. Cleaning pipeline inspection gauges
are not included within the definition of
natural gas transmission or distribution
property for purposes of this revenue
procedure.
.29 Odorizing equipment. “Odorizing
equipment” means equipment that injects
an odorant or other additive into the gas
so that leaks can be detected by the sense
of smell.
.30 Gas detection equipment. “Gas
detection equipment” means equipment
that indicates the existence of natural gas
in a specific area.
.31 Electric supply equipment. “Elec-
tric 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. “Lique-
faction 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 electro-
chemical 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 lin-
ear 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 prop-
erty, including any unit of property rules
described therein. A taxpayer using the
NGSH Method must also apply the safe

Bulletin No. 2023–18 811 May 1, 2023
harbor method for distribution service line
costs as provided in section 5.07 of this
revenue procedure. Moreover, a taxpayer
using the NGSH Method may, but is not
required to, apply the safe harbor method
for non-linear property provided in sec-
tion 5.04 of this revenue procedure to the
direct and indirect costs of repairing, main-
taining, 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 sec-
tion 5.05 of this revenue procedure and
the aggregation rules provided in section
5.06 of this revenue procedure to prop-
erty 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 sec-
tion 5.08 of this revenue procedure.
(2) Solely for purposes of this revenue
procedure, the IRS will respect a reason-
able 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 reason-
able 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 determin-
ing 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 capi-
talized under the NGSH Method are
capital expenditures and must be taken
into account through a charge to capital
account or basis. Amounts that are paid or
incurred for MACRS property and that are
capitalized under this NGSH Method are
accounted for in the manner described in
section 5.08 of this revenue procedure.
.02 Safe harbor method for linear
property—application to transmission
property.
(1) Unit of property for linear trans-
mission property. For purposes of this
revenue procedure, the unit of property
for linear natural gas transmission prop-
erty is the linear property within each
hydraulic subsystem as defined in sec-
tion 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 connec-
tion 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 junc-
tion 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 prop-
erty is determined by the length of the
line replaced. If more than 10 percent of
the length of the unit of linear transmis-
sion 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 transmis-
sion property is replaced, the cost of the
replacement is not required to be capital-
ized under § 263(a) or § 263A. The cost
of the replacement includes the direct and
indirect costs of replacing the pipe and
any associated linear property, including,
but not limited to, connectors, cathodic
protection, valves, casing, tunnels, instru-
mentation and controls, and structural
supports for such property.
(3) Blanket work orders.
(a) Allocation. To the extent a tax-
payer cannot specifically identify whether
amounts charged to a blanket work order
are for a replacement of linear transmis-
sion 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 cost-
ing $50,000 or less is not required to
capitalize the costs of replacing linear
transmission property charged to the blan-
ket work order. Replacements of property
qualifying under this de minimis rule
are not taken into account in determin-
ing 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 prop-
erty—application to distribution property.
(1) In general. For purposes of deter-
mining whether the costs of replacing
linear distribution property must be cap-
italized under the NGSH Method, the
unit of linear distribution property is not
defined. Instead, the taxpayer must ini-
tially determine whether the costs are for
the replacement of distribution mains as
defined in section 4.18 of this revenue
procedure or are distribution service line
costs as defined in section 4.20 of this rev-
enue 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 sec-
tion 5.07 of this revenue procedure.
(2) Simplified rule for replacements of
distribution mains. Whether a taxpayer
using the safe harbor method for lin-
ear 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 dis-
tribution 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 lin-
ear property, including, but not limited to,
connectors, cathodic protection, valves,
casing, tunnels, instrumentation and con-

May 1, 2023 812 Bulletin No. 2023–18
trols, and structural supports for such
linear property.
(3) Blanket work orders.
(a) Allocation. To the extent a tax-
payer cannot specifically identify whether
amounts charged to a blanket work order
are for the replacement of distribution
mains greater than four miles, the tax-
payer may use any reasonable method to
allocate costs charged to the blanket work
order if the reasonable method is consis-
tently applied by the taxpayer.
(b) De minimis charges. A taxpayer
that adheres to a policy that limits per-
event charges under a blanket work
order to replacements of property costing
$50,000 or less is not required to capitalize
the costs of distribution mains replace-
ments 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. How-
ever, 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 prop-
erty 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 Appen-
dix A for that unit of property. Similarly,
a taxpayer that uses a major component
definition provided in Appendix A must
also use the unit of property definition
provided in Appendix A associated with
that major component.
(3) Simplified rule for replacements
of non-linear property. The safe harbor
method for non-linear property applies to
the direct and indirect costs paid or incurred
to repair, maintain, replace, or improve
the taxpayer’s non-linear transmission
and distribution property. If the taxpayer
replaces a unit of non-linear property or
a major component of a unit of non-linear
property as identified in Appendix A, then
the taxpayer must capitalize the amounts
paid to replace the unit of non-linear prop-
erty 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 com-
ponent 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 activ-
ities, 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 dis-
tribution property, and these costs relate
to per se capital expenditures described
under section 5.05 of this revenue proce-
dure, 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 proce-
dure, a taxpayer using the NGSH Method
must capitalize the direct and indirect
costs described in section 5.05(1)(a)
through (j) of this revenue procedure to
the extent these costs are paid or incurred
with respect to linear property or non-lin-
ear 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 sec-
tion 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-lin-
ear 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 sim-
ilar 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 casu-
alty loss), or takes the adjusted basis of
the replaced property into account in real-
izing gain or loss resulting from a sale or
exchange of the replaced property;
(h) The costs of repairing or replacing
all or part of property as a result of dam-
age 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 pur-
poses of applying section 5.05(1)(b) of
this revenue procedure to linear trans-
mission property or linear distribution
property, an expenditure for linear prop-

Bulletin No. 2023–18 813 May 1, 2023
erty materially increases capacity to one
or more existing or potential customers
if the work performed increases capac-
ity 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 rev-
enue 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 mate-
rially increase capacity to linear property
under section 5.05(2)(a) of this revenue
procedure if the taxpayer can establish
with reasonable certainty, through its
books and records, that the principal pur-
pose 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 prop-
erty, 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 distri-
bution service line costs associated with
distribution mains. If the taxpayer can
identify with reasonable accuracy distri-
bution service line costs associated with
distribution main costs that are treated
as per se capital expenditures under this
section 5.05, then the identified distri-
bution service line costs are also treated
as per se capital expenditures under this
section 5.05. For rules regarding identi-
fied and unidentified distribution service
line costs, see section 5.07 of this reve-
nue procedure.
(5) Coordination with other rules.
Replacements of property for which
the replacement costs are per se capi-
tal expenditures under this section 5.05
are not taken into account in determin-
ing whether more than 10 percent of the
length of the unit of linear transmission
property is replaced for purposes of apply-
ing 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 reve-
nue 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 prop-
erty, 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 dis-
tribution company that supplies gas to an industrial
customer via a three-inch diameter distribution ser-
vice 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 correspon-
dence 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 instal-
lation of a second three-inch distribution service line,
throughput of gas to the customer is increased by 100
percent.
(ii) The cost of installing the second distribution
service line is a per se capital expenditure under sec-
tion 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 distribu-
tion 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 trans-
mission 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 specif-
ically indicate a principal purpose for replacing the
seven-mile segment. Accordingly, the cost of replac-
ing 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 trans-
mission pipeline that is 300 miles in length. Section
B of this transmission pipeline runs for 80 miles
between two compressor stations and is a hydrau-
lic 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 dis-
tribution 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 per-
forms 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

May 1, 2023 814 Bulletin No. 2023–18
result of the safety risk assessment. W can identify
with reasonable accuracy the distribution service line
costs that are associated with the distribution mains
replacement.
(ii) Pursuant to section 5.05(2)(b) of this revenue
procedure, the cost to replace the distribution main is
not a per se capital expenditure under section 5.05(1)
(b) of this revenue procedure because the taxpayer’s
books and records indicate that the principal purpose
of the distribution main replacement was to reduce
safety risk. Additionally, because the length of the
distribution main replacement is less than four miles,
the cost of the distribution main replacement is not
required to be capitalized under section 5.03(2) of
this revenue procedure. Similarly, because W can
identify the costs of replacing the distribution ser-
vice lines with the distribution main replacement, the
cost of replacing the associated distribution service
lines is not a per se capital expenditure under sec-
tion 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 distribu-
tion 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 deliv-
ery 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 rev-
enue procedure. Additionally, because the cost of
the distribution main replacement is a per se capital
expenditure, the cost of replacing the associated dis-
tribution 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 distri-
bution 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 sys-
tem 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 pro-
cedure, 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 capital-
ized under section 5.03(2) of this revenue procedure.
(g) Example 7. (i) T is a local natural gas distri-
bution 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 con-
siders polyethylene pipe to be better pipe for several
reasons. T replaces three miles of four-inch diame
-
ter iron pipe in its distribution mains with four-inch
diameter polyethylene pipe. There is no change in
the throughput of gas to customers served by the dis-
tribution 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. Notwithstand-
ing 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 reve-
nue procedure because the pipeline continues to run
between the same two endpoints. Additionally, the
cost of the relocation is not required to be capital-
ized 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 deter-
mining whether the applicable thresholds
for capitalization of property provided in
sections 5.02, 5.03, and 5.04 of this rev-
enue procedure are met, a taxpayer must
aggregate multiple replacements if all of
the following requirements are met:
(a) The replacements are within –
(i) the same unit of property, for
non-linear property and linear transmis-
sion 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 replace-
ments 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 “autho-
rizing document” means the following:
(i) a regulatory commission decision
that requires replacements as part of an
identified program aimed at a specific
purpose;
(ii) a written project authorization
aimed at a specific purpose;
(iii) a work order as defined under sec-
tion 4.08 of this revenue procedure; or
(iv) a blanket work order as defined
under section 4.09 of this revenue pro-
cedure 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 autho-
rizes 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 regula-
tory commission decision), aggregation is
based on the most general authoriz-
ing document that meets the requirements
of section 5.06(1)(c) of this revenue proce-
dure. 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 pursu-
ant to this authorizing document is not
required. However, if a subsequent more
specific authorizing document implement-
ing that same program or project provides
that certain replacements are expected

Bulletin No. 2023–18 815 May 1, 2023
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 require-
ments 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 sec-
tion 5.06(1) of this revenue procedure
are aggregated without regard to whether
they are performed in one year or multiple
years.
(5) Modifications. Modifications to an
authorizing document, or to the work done
pursuant to an authorizing document, that
occur within the taxable year are taken
into account in determining whether to
aggregate replacements, and whether to
capitalize the expenditures, in that taxable
year, but do not affect the aggregation of
replacements pursuant to that authorizing
document in a prior taxable year.
(6) Anti-abuse rule. If a taxpayer acts
(a) to divide closely related transmis-
sion 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 aggre-
gation rules under this section 5.06, rather
than for non-tax business reasons, appro-
priate 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 prop-
erty, 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 qual-
ifying disposition).
(a) Example 1. (i) R is a natural gas distribution
company in State A. The Public Utility Commission
(Regulator) of State A sets the rates and approves
tariffs for R. Regulator issues Rate Order 12345 as a
result of certain rate proceedings. Rate Order 12345
allows for the incremental recovery of up to an
additional $30 million annually in revenue through
rates and tariffs. Rate Order 12345 states that these
dollars are for the recovery of incremental operating
expense, maintenance expense, and return on invest-
ment 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 rev-
enue billed to incremental expense and include R’s
allowed return on investment. The specific distribu-
tion 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 replace-
ments; (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 replace-
ments; 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 dis-
tribution company. Based on estimated general
maintenance and upgrade costs and anticipated rev-
enues 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 proce-
dure, an aggregation of pipeline replacements is not
required under this section 5.06 because Q’s bud-
get 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 replace-
ments 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 replace-
ments under the blanket work order to repair leaks.
For purposes of determining whether the replace-
ment 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 blan-
ket 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 distribu-
tion 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 spec-
ifies 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 iden-
tified, O prepares work orders to replace the Type L
pipe. In one ZIP Code delivery area, O identifies six
sections of Type L distribution mains, totaling eight
miles, and each of these sections are replaced under
six separate work orders, as they are identified. Each
work order identifies the location and the amount
of the distribution mains to be replaced. Each work
order is for a replacement of less than four miles of
distribution mains.
(ii) For purposes of determining whether the
replacement costs are capitalized under section
5.03 of this revenue procedure, the replacements
are not aggregated under this section 5.06 under the
Regulator’s order because, although the order is an
authorizing document within the meaning of section
5.06(2) of this revenue procedure, the order does not
identify the amount or costs of the distribution mains
to be replaced, as required by section 5.06(1)(c)(ii)
of this revenue procedure. Similarly, the replace-
ments are not aggregated under the written project
authorization issued by O because the authorization
does not identify the amount or the costs of the dis-
tribution 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 authoriz-
ing document for the replacement of less than four
miles of distribution mains, the costs of the replace-
ments are not required to be capitalized under section
5.03 of this revenue procedure.
(e) Example 5. (i) The facts are the same as in
Example 4, except that in response to the Regulator’s
order, in Year 1, O’s management issues a written
project authorization for the replacement of all Type
L pipe in County Z in State B, identifying the quan-
tity 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 com-
pleted but there is no reason to expect that the project
will take longer than five years.
(ii) For purposes of determining whether the
replacement costs are capitalized under section 5.03
of this revenue procedure, the replacements are
aggregated under this section 5.06 pursuant to O’s
written project authorization, which authorizes the
replacement of distribution mains for a specific pur-
pose 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 sin-

May 1, 2023 816 Bulletin No. 2023–18
gle 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 reve-
nue 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 autho-
rization 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 opera-
tions. It is reasonable to expect that the replacements
under this project authorization would not be com-
pleted 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 dif-
ferent 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 writ-
ten 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 rea-
sonable to expect that the replacements will not be
completed within five years. However, the replace-
ment 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 autho-
rizing 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 sepa-
rate authorizing documents. Because each of these
three work orders is for the replacement of less than
four miles of distribution mains, the costs of these
distribution main replacements are not required to
be capitalized under section 5.03 of this revenue
procedure.
(g) Example 7. (i) M is a natural gas distribution
company. M budgets $10 million for the replacement
of distribution mains that run through subdivisions
A and B, which are in ZIP code delivery area H. The
budget directs the work to be done through a writ-
ten 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 proj-
ect 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 aggre-
gate 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 capi-
talized under section 5.03 of this revenue procedure.
(h) Example 8. (i) L is a natural gas transmission
company that operates a natural gas transmission
line in State C. In Year 1, L conducts an internal
inspection of a 100-mile section of the transmission
line, a hydraulic subsystem that is a separate unit of
property under section 5.02(1) of this revenue pro-
cedure. 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 war-
ranted. The replacement of the nine miles, which was
performed under two separate work orders, is com-
pleted 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 authoriza-
tion 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 trans-
mission property, the cost of the replacements is not
required to be capitalized under section 5.02 of this
revenue procedure.
(i) Example 9. (i) The facts are the same as in
Example 8, except that the January Year 1 project
authorization required the replacement of only nine
miles (9 percent) of L’s 100-mile hydraulic sub-
system. 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 proj-
ect 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 sta-
tus 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 capi-
talized 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 manage-
ment 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 addi-
tional miles of pipe, and the work is completed. In
aggregate, only nine total miles of pipe are replaced
under the written project authorization.
(ii) For purposes of determining whether the
replacement costs are capitalized under section 5.02
of this revenue procedure, the replacement work
expected to be performed in Year 1, Year 2, and Year
3 is aggregated pursuant to the January Year 1 proj-
ect 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 modifi-
cations 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 sur-
vey, the January Year 1 written project authorization
requires the replacement of only nine miles of pipe
(nine percent of the 100-mile unit of property). Eight
miles are replaced in Years 1 and 2. In Year 3, L’s
engineers determine that five additional miles of
pipe should be replaced for a total of 13 miles and
request that management modify the project and
authorize additional funds to complete the 13-mile
replacement. The project authorization is modified

Bulletin No. 2023–18 817 May 1, 2023
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 replace-
ments 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 aggre-
gation 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 capital-
ized using the rules described in sections
5.07(2) and 5.07(3) of this revenue proce-
dure. The rules in section 5.07(2) of this
revenue procedure determine the treat-
ment of distribution service line costs that
a taxpayer can identify with reasonable
accuracy as paid or incurred for a proj-
ect described in section 5.07(2) of this
revenue procedure. The rules in section
5.07(3) of this revenue procedure deter-
mine 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 sec-
tion 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 cap-
ital 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 expendi-
tures 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 replace-
ments that are more than four miles), are
required to be capitalized;
(ii) Identified distribution service line
costs, other than per se capital expendi-
tures described in section 5.07(2)(a) of
this revenue procedure, associated with
distribution main replacements that are
not required to be capitalized under sec-
tion 5.03(2) of this revenue procedure
(that is, associated with distribution main
replacements that are four miles or less),
are not required to be capitalized; and
(iii) Identified distribution service line
costs, other than per se capital expendi-
tures 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 dis-
tribution service line costs. To the extent a
taxpayer cannot identify distribution ser-
vice 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 capital-
ized under §§ 263(a) and 263A. Step 1
determines the total amount of unidenti-
fied 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 deter-
mined in Step 1 by the capitalization ratio
to determine the amount of its unidenti-
fied distribution service line costs that are
required to be capitalized.
(a) Step 1. Determine total unidentified
distribution service line costs. To deter-
mine the total unidentified distribution
service line costs, the taxpayer’s total dis-
tribution service line costs for the taxable
year are reduced by the identified distribu-
tion service line costs described in section
5.07(2) of this revenue procedure.
(b) Step 2. Determine total distri-
bution main replacement costs not
associated with identified distribution
service line costs (denominator of cap-
italization 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 replace-
ment costs, including distribution main
replacement costs qualifying under the de
minimis rule for blanket orders under sec-
tion 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 distri-
bution 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 distribu-
tion 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 distribu-
tion service line costs (numerator of
capitalization ratio). To determine the
capitalized distribution main replacement
costs not associated with identified distri-
bution 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 replace-
ment 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

May 1, 2023 818 Bulletin No. 2023–18
associated with identified distribution ser-
vice 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, multi-
ply the taxpayer’s capitalization ratio, as
determined under Step 4, by the taxpay-
er’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
)
×
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)
[]
Capitalization ratio (Step 4)
(4) Example.
(a) Facts. K is a corporation that oper-
ates a natural gas distribution system in
State D. K files its Federal income tax
return on an accrual method and a cal-
endar year basis and uses the NGSH
Method. K uses work orders and blanket
work orders to authorize replacement and
repair work on its distribution system.
K’s work orders detail the scope of each
individual project and capture direct and
indirect costs for labor, construction, and
materials. K’s work orders for the replace-
ment of distribution mains identify the
distribution service lines that are replaced
in conjunction with these distribution
main replacements.
In Year 1, K incurs costs of $9 million
with respect to replacements of linear
distribution property. Of this amount,
K incurs $8 million for replacements of
distribution mains (including $1 million
in distribution main replacement costs
qualifying under the de minimis rule for
blanket work orders), and K incurs $1 mil-
lion for distribution service lines costs. Of
the $1 million K incurs for work on dis-
tribution service lines, K incurs $150,000
for distribution service line costs that are
per se capital expenditures, including dis-
tribution 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 distri-
bution 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 replace-
ments exceeding four miles with identified
distribution service line costs that are cap-
italized under section 5.07(2)(b)(i) of this
revenue procedure. K can also associate
$2.5 million of the $3.5 million K incurs
for distribution main replacements of four
miles
or less with identified distribution
service line costs that are not required to
be capitalized under section 5.07(2)(b)(ii)
of this revenue procedure.
(b) Step 1. To determine its total
unidentified distribution service line costs,
K begins with the $1 million it incurs for
its work on distribution service lines for
Year 1 and subtracts its identified dis-
tribution 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 distri-
bution 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 reve-
nue 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 ser-
vice line costs equals $450,000 ($150,000
+ $60,000 + $140,000 + $100,000). K
subtracts the total identified distribu-
tion 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 distri-
bution 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 distri-
bution main replacement property of $8
million (which includes the $1,000,000
for expenditures of less than $50,000 on
blanket work orders qualifying under the
de minimis rule) and decreasing these
costs by (i) $2 million, the distribution
main replacement costs that are per se
capital expenditures under section 5.05

Bulletin No. 2023–18 819 May 1, 2023
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 rev-
enue procedure; and (iii) $2.5 million,
the distribution main replacements costs
associated with identified distribution ser-
vice 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 mil-
lion because such costs are for distribution
main replacements over four miles. Then,
K reduces this amount by $600,000, the
distribution main replacement costs asso-
ciated 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 cap-
italization ratio to be applied to its total
unidentified distribution service line costs
by dividing the total capitalized cost of
distribution main replacements that are
not associated with identified distribution
service line costs of $900,000 by the total
costs of distribution main replacements
that are not associated with distribution
service line costs of $2.9 million. The
quotient of 0.31 ($900,000 / $2.9 million)
is the capitalization ratio.
(f) Step 5. Finally, K determines the
unidentified distribution service line
costs that must be capitalized by multi-
plying 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 transi-
tion 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 ser-
vice in or after year of change. Natural
gas transmission and distribution prop-
erty 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 ser-
vice before year of change. Natural gas
transmission and distribution property
described in section 5.08(2)(a) of this
revenue procedure. See section 5.08(2) of
this revenue procedure for the application
of general asset accounts to this property.
(2) Late general asset election required
for certain property placed in service
before year of change.
(a) In general. A taxpayer that changes
to the NGSH Method must change its
method of accounting to the NGSH
Method on either a cut-off basis, as per-
mitted 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 tax-
payer that changes to the NGSH Method
of accounting with a cut-off or § 481(a)
adjustment must also make a late gen-
eral 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 rev-
enue 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, sec-
ond, 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 pro-
cedure 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 pro-
viding exceptions to certain per se capital
expenditure rules applicable to a taxpayer
that changes to the NGSH Method for its
first taxable year ending after May 1, 2023
with a § 481(a) adjustment.
(ii) Change made in taxpayer’s first,
second, or third taxable years on a cut-off
basis. If a taxpayer changes to the NGSH
Method for the taxpayer’s first, second,
or third taxable year ending after May 1,
2023 on a cut-off basis under section 6.04
of this revenue procedure, the taxpayer
must make a late general asset account
election for linear and non-linear property,
as applicable, that is described in section
5.08(2)(a) of this revenue procedure and
that was capitalized by the taxpayer under
its prior method of accounting in taxable
years prior to the year of change.
(iii) Change made in fourth or subse-
quent 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 gen-
eral 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 correspond-
ing 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 tax-
able 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

May 1, 2023 820 Bulletin No. 2023–18
the taxpayer had previously changed to
and continues to apply the safe harbor
method for linear property.
(b) Time and manner of making late
general asset account election. A taxpayer
that changes to the safe harbor method for
linear property must make the late gen-
eral 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 informa-
tion 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 account-
ing 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 tax-
payer 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 taxpay-
er’s present methods of accounting are not
in accord with § 1.168(i)-1, the taxpayer
must change to the methods of account-
ing permitted under § 1.168(i)-1 no later
than the first taxable year that the taxpayer
uses the natural gas transmission and dis-
tribution property safe harbor method of
accounting.
(d) Property for which the taxpayer did
not make a general asset account elec-
tion. For any property described in section
5.08(2)(a) of this revenue procedure, the
term “property for which the taxpayer did
not make a general asset account elec-
tion” 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 clar-
ified 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) adjust-
ment—certain per se capital expenditure
rules not applied in prior years. If a tax-
payer 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 tax-
able year ending after May 1, 2023 with
a § 481(a) adjustment, the per se capi-
tal 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 prop-
erty for the taxpayer’s fourth taxable year
ending after May 1, 2023, or for any subse-
quent taxable year, must make the change
on a cut-off basis, and is not eligible to use
the NGSH Method rules provided in sec-
tions 5.02, 5.03, 5.05, 5.06, and 5.07 of this
revenue procedure for any linear property
expenditures paid or incurred prior to the
year of change. A taxpayer that changes
to the safe harbor method for non-linear
property for the taxpayer’s fourth taxable
year ending after May 1, 2023, or for
any subsequent taxable year, must make
this change on a cut-off basis, and is not
eligible to use the NGSH Method rules
provided in sections 5.04, 5.05, and 5.06
of this revenue procedure for any non-lin-
ear 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 taxpay-
er’s fourth taxable year ending after
May 1, 2023, or for any subsequent tax-
able year, and did not properly capitalize
under §§ 263(a) and 263A any linear
property expenditures or non-linear prop-
erty expenditures, as applicable, paid or
incurred prior to the year of change, the
taxpayer also must change its method of
accounting to properly capitalize such
expenditures under §§ 263(a) and 263A
for the same year of change. The taxpayer
must change to a method of accounting
described under sections 11.08, 12.01,
12.02, 12.08, and/or 12.12 of Rev. Proc.
2022-14, 2022-7 I.R.B. 1, as applicable,
and such method change must be made
on the same Form 3115, Application for
Change in Accounting Method, on which
the taxpayer changes to the safe harbor
method for linear property and the safe
harbor method for non-linear property, as
applicable.
(4) Examples. The following examples
illustrate the application of this section
5.08. In each example, it is assumed that
the taxpayer (i) is a C corporation that
files its Federal income tax returns on an
accrual method and a calendar taxable
year basis, (ii) is within the scope of this
revenue procedure, (iii) placed in ser-
vice 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 gen-
eral 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 proce-
dure. It is also assumed, unless otherwise
stated, that the costs of linear and non-lin-
ear 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,

Bulletin No. 2023–18 821 May 1, 2023
5.04, 5.06, and 5.07 of this revenue proce-
dure, and that these costs would not have
been treated as per se capital expenditures
under sections 5.05(1)(a)-(f), (i), or (j)
of this revenue procedure. Further, it is
assumed that § 1.168(i)-1(e)(3) (special
rules for certain dispositions of assets in
general asset accounts) does not apply for
the first taxable year that the taxpayer uses
the NGSH Method and for any subsequent
taxable year. Moreover, for purposes of
these examples, “Year 1” refers to the
taxpayer’s first taxable year ending after
May 1, 2023, “Year 2” refers to the tax-
payer’s second taxable year ending after
May 1, 2023, and “Year 4” refers to the
taxpayer’s fourth taxable year ending after
May 1, 2023. The following examples do
not address the treatment of depreciation
or the requirement or computation of the
§ 481(a) adjustment, if applicable, for pur-
poses of changing the taxpayer’s methods
of accounting under section 6 of this reve-
nue procedure.
(a) Example 1. (i) J is a natural gas transmission
company. Before Year 1, J owned and placed in ser-
vice natural gas transmission property at a cost of
$100 million before any dispositions or additions.
Before Year 1, J replaced parts of such property that
had an original cost of $10 million and incurred $12
million for the cost of such replacements. On its
Federal income tax returns before Year 1, J recog-
nized losses upon the dispositions of that $10 million
of property and deducted $12 million for the cost
of the replacements under § 162(a). J files a Form
3115 with its Federal income tax return for Year 1
to change its methods of accounting for linear and
non-linear property to use the NGSH Method.
(ii) Pursuant to the special rule in section 5.08(3)
(a) of this revenue procedure, the per se capital
expenditure rules in section 5.05(1)(g) and (h) of this
revenue procedure do not apply to the replacement
cost of $12 million that J deducted under § 162(a)
before J’s Year 1. Accordingly, this $12 million cost
of the replacements is not a per se capital expendi-
ture 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 transmis-
sion property that had an original cost of $2
million and incurred $3.5 million for the cost of such
replacements.
(ii) As a result of the late general asset account
election in Example 1, the $2 million of the natu-
ral gas transmission property that J replaced during
Year 1 is in a general asset account. Pursuant to
§ 1.168(i)-1(e)(2), J does not recognize a loss upon
the disposition of that $2 million of property and
continues to depreciate that property on its Federal
income tax return for Year 1 and subsequent taxable
years.
(iii) Because J did not recognize a loss upon the
disposition of that $2 million of property, the cost of
$3.5 million for replacing a part of the natural gas
transmission property during Year 1 is not a per se
capital expenditure under section 5.05(1)(g) or (h)
of this revenue procedure. Accordingly, for its Fed-
eral 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 distri-
bution company. Before Year 1, I owned and placed
in service gas distribution property at a cost of $120
million before any dispositions or additions. Before
Year 1, I replaced parts of such property that had an
original cost of $10 million and incurred $12 mil-
lion for the cost of such replacements. On its Federal
income tax returns before Year 1, I recognized losses
upon the dispositions of that $10 million of property
and deducted $12 million for the cost of the replace-
ments under § 162(a). During Year 1, I replaced a
part of the natural gas distribution property that had
an original cost of $2 million and incurred $3 mil-
lion for the cost of such replacements. On its Federal
income tax return for Year 1, I recognized a loss upon
the disposition of the $2 million of replaced property,
and deducted $3 million for the cost of the replace-
ments under § 162(a). I files a Form 3115 with its
Federal income tax return for Year 2 to change its
methods of accounting for its linear and non-linear
property to use the NGSH Method.
(ii) Because I filed its method change in Year 2,
the special rule for certain per se capital expenditures
under section 5.08(3)(a) of this revenue procedure
does not apply to taxable years ending before the
taxpayer’s first taxable year for which the taxpayer
changes. Accordingly, the per se capital expenditure
rules in section 5.05(1)(g) and (h) of this revenue pro-
cedure apply to the replacement cost of $12 million
that I deducted under § 162(a) on its Federal income
tax returns before Year 1, and to the replacement cost
of $3 million that I deducted under § 162(a) on its
Federal income tax return for Year 1. Therefore, the
total cost of $15 million for these replacements is a
per se capital expenditure, and must be capitalized,
under the NGSH Method.
(iii) At the beginning of Year 2, I owns natural
gas distribution property at a cost of $123 million
($120 million - $10 million + $12 million - $2 mil-
lion + $3 million). Because Year 2 is I’s second
taxable year ending after May 1, 2023, under section
5.08(2)(a)(i) of this revenue procedure, I must make
a late general asset account election on its Form 3115
to include in general asset accounts all of the $123
million of natural gas distribution property that I
owns at the beginning of Year 2. In addition, for its
Federal income tax return for Year 2, I must apply
the NGSH Method to all amounts paid or incurred in
Year 2 that are subject to the NGSH Method, and I
must make general asset account elections to include
in general asset accounts all costs capitalized under
the NGSH Method in Year 2.
(d) Example 4. (i) H is a local natural gas distri-
bution 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 Fed-
eral income tax returns before Year 4, H recognized
losses upon the dispositions of that $30 million of
property and capitalized $45 million for the cost
of the replacements under § 263(a). H files a Form
3115 with its Federal income tax return for Year 4 to
change its methods of accounting for its linear and
non-linear property to use the NGSH Method.
(ii) At the beginning of Year 4, H owns natural
gas distribution property at a cost of $165 million
($150 million - $30 million + $45 million). Because
Year 4 is H’s fourth taxable year ending after May
1, 2023, under section 5.08(2)(a)(iii) of this revenue
procedure, H must make a late general asset account
election on its Form 3115 to include in general asset
accounts all of the $165 million of natural gas distri-
bution 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 prop-
erty 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 allow-
ance 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 tax-
able 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 cap-
italized separately under § 263A(a)(1)
(B) and (b)(1) as direct or indirect costs
of producing gas transmission and dis-
tribution property. However, a taxpayer
that produces natural gas or acquires nat-
ural gas for resale in its trade or business

May 1, 2023 822 Bulletin No. 2023–18
must capitalize under § 263A direct and
allocable indirect costs of producing or
acquiring such property or any other prop-
erty 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 reve-
nue procedure is a change in method of
accounting to which the provisions of
§§ 446 and 481, and the corresponding
regulations, apply. However, section 6.04
of this revenue procedure allows certain
taxpayers to choose to change to these
methods of accounting on a cut-off basis.
A taxpayer that wants to change to the
methods of accounting described in this
revenue procedure must, if eligible, use
the automatic change procedures in Rev.
Proc. 2015-13, 2015-5 I.R.B. 419, as clar-
ified 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 extrapo-
lation 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. Extrap-
olation methodologies not permitted in
Appendix B are not permitted under the
NGSH Method.
.04 Optional cut-off basis for first 3
taxable years.
(1) Availability of change on a cut-
off basis. A taxpayer that changes to the
safe harbor method for linear property
for the taxpayer’s first, second, or third
taxable year ending after May 1, 2023,
may choose to change to this method of
accounting on a cut-off basis. See section
2.07 of Rev. Proc. 2015-13. A taxpayer
that chooses to change to the safe harbor
method for linear property on a cut-off
basis under this section 6.04, and also
changes to the safe harbor method for
non-linear property for the taxpayer’s first,
second, or third taxable year ending after
May 1, 2023, also must change to the safe
harbor method for non-linear property on
a cut-off basis, regardless of the year of
this change. A taxpayer that changes to the
safe harbor method for linear property for
the taxpayer’s first, second, or third tax-
able 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 prop-
erty 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 dis-
tribution 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 account-
ing (NGSH Method) described in Rev.
Proc. 2023-15. Specifically, this change
applies to a taxpayer that wants to change
to “the safe harbor method for linear
property” or “the safe harbor method for
non-linear property” and other applica-
ble 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 har-
bor method for linear property and wants
to change to the safe harbor method for
non-linear property for a subsequent tax-
able year.
(b) Inapplicability. This change does
not apply to the making of a late general
asset account election other than in accor-
dance 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 appli-
cable, 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.

Bulletin No. 2023–18 823 May 1, 2023
(3) Manner of making change.
(a) Late general asset account election.
(i) The late general asset account elec-
tion 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 gen-
eral asset account is equal to the sum of
the unadjusted depreciable basis as of
the beginning of the year of change for
all assets included in that general asset
account. The beginning balance of the
depreciation reserve of each general asset
account is equal to the sum of the greater
of the depreciation allowed or allowable
as of the beginning of the year of change
for all assets included in that general asset
account.
(ii) For the late general asset account
election change described in section
5.08(2) of Rev. Proc. 2023-15, the tax-
payer must attach to its Form 3115 a
statement providing that the taxpayer
agrees to the following additional terms
and conditions:
(A) The taxpayer consents to, and
agrees to apply, all the provisions of
§ 1.168(i)-1 to the assets that are subject
to the election specified in section 5.08(2)
of Rev. Proc. 2023-15; and
(B) Except as provided in
§ 1.168(i)-1(c)(1)(ii)(A), (e)(3), (g), or (h),
the election made by the taxpayer under
section 5.08(2) of Rev. Proc. 2023-15 is
irrevocable and will be binding on the tax-
payer 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 trans-
mission 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 proce-
dure, 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 nega-
tive, in computing taxable income for the
year of change in the manner provided in
section 7.03 of Rev. Proc. 2015-13. The
entire net § 481(a) adjustment includes all
aspects of the NGSH Method described in
Rev. Proc. 2023-15, including a change
to the methods of accounting permitted
under § 1.168(i)-1 pursuant to section
5.08(2) of Rev. Proc. 2023-15. However,
a § 481(a) adjustment is neither required
nor permitted for the late general asset
account election described in section
5.08(2) of Rev. Proc. 2023-15. Further,
a § 481(a) adjustment is neither required
nor permitted if the taxpayer chooses to
change to the NGSH Method on a cut-
off basis under section 6.04 of Rev. Proc.
2023-15 or if the taxpayer changes to this
method during the time described in sec-
tion 5.08(2)(a)(iii) of Rev. Proc. 2023-15.
(b) Repair allowance property. A tax-
payer 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 allow-
ance 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 methodol-
ogy provided in Appendix B to Rev. Proc.
2023-15 (Appendix B) in determining the
§ 481(a) adjustment amount if the tax-
payer is within the scope of section 1.02
of Appendix B. Extrapolation methodolo-
gies not permitted in Appendix B are not
permitted under the NGSH Method.
(5) No audit protection for certain tax-
payers. If a taxpayer chooses to change
to the NGSH Method described in Rev.
Proc. 2023-15 on a cut-off basis as per-
mitted 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 sin-
gle net § 481(a) adjustment for all such
changes.
(b) A taxpayer making changes under
this section 3.12 and changes under sec-
tion 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 coor-
dinating 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, pro-
vided that the taxpayer is not prohibited
from filing an automatic change under
the eligibility rules under section 5 of
Rev. Proc. 2015-13. For changes required
to be filed on a single Form 3115 under
this section, the taxpayer must enter the
designated automatic accounting method

May 1, 2023 824 Bulletin No. 2023–18
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 tax-
able year ending after May 1, 2023 and
is also required to change its method of
accounting to properly capitalize its lin-
ear property or non-linear property costs
under § 263(a) and/or § 263A under sec-
tion 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, pro-
vided 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 tax-
payer 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 exam-
ple, 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 distribu-
tion 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 trans-
mission property or distribution property
placed in service by the taxpayer in any
taxable year before the first taxable year
that the taxpayer uses the NGSH Method,
(e) is changing its methods of accounting
for both linear property and non-linear
property under the NGSH Method for the
same taxable year, and (f) is not chang-
ing 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 tax-
able years, and (c) the taxpayer’s natural
gas transmission and distribution prop-
erty 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) (spe-
cial 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 end-
ing after May 1, 2023, and “Year 4” refers
to the taxpayer’s fourth taxable year end-
ing after May 1, 2023.
(a) Example 1. (i) X is a local natural gas distri-
bution 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 Fed-
eral 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 mil-
lion. X files a Form 3115 with its Federal income tax
return for Year 1 to change its methods of account-
ing to use the NGSH Method described in Rev. Proc.
2023-15.
(ii) Because Year 1 is X’s first taxable year end-
ing 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 replace-
ments is not treated as a per se capital expenditure
under the NGSH Method. Therefore, at the begin-
ning 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 depreci-
ation allowed or allowable before the beginning of
Year 1 for such property as the beginning balances
of the depreciation reserves. The late general asset
account election change is made on a modified cut-
off method and, therefore, a § 481(a) adjustment is
neither required nor permitted for the late general
asset account election change.
(iii) On its Form 3115 to change to the NGSH
Method provided under Rev. Proc. 2023-15, the
net negative § 481(a) adjustment for this change is
$11,200,000 (deduction of $12 million for the cost
of the replacements before Year 1 less depreciation
of $800,000 for such replacement assets before Year
1) and is deducted in computing X’s taxable income
for Year 1.
(b) Example 2. (i) The facts are the same as in
Example 1, except that X files a Form 3115 with
its Federal income tax return for Year 2 to change
its method of accounting to use the NGSH Method
described in Rev. Proc. 2023-15, and, before Year
2, X deducted depreciation of $1,000,000 on the
replacement cost of $12 million.
(ii) Because X filed its method change in Year
2, the special rule under section 5.08(3)(a) of Rev.
Proc. 2023-15 does not apply to the replacement
cost of $12 million that X capitalized under § 263(a)
on its Federal income tax returns before Year 1.
Accordingly, section 5.05(1)(g) and (h) of Rev. Proc.
2023-15 apply to the replacement cost of $12 million
that X capitalized on its Federal income tax returns
before Year 2. The total cost of $12 million for this
replacement is a per se capital expenditure, and must
be capitalized, under the NGSH Method.
(iii) At the beginning of Year 2, X is treated under
the NGSH Method as owning natural gas distribution
property at a cost of $122 million ($120 million - $10
million + $12 million). Under section 5.08(2)(a)(i)
of Rev. Proc. 2023-15, X must make a late general
asset account election on its Form 3115 to include
in general asset accounts all of the $122 million of
natural gas distribution property that X owns at the
beginning of Year 2. These general asset accounts
also must include the total depreciation allowed or
allowable before the beginning of Year 2 for such
property as the beginning balances of the deprecia-
tion reserves. The late general asset account election
change is made on a modified cut-off method and,
therefore, a § 481(a) adjustment is neither required
nor permitted for the late general asset account
election.
(iv) On its Form 3115 to change to the NGSH
Method under Rev. Proc. 2023-15, the net § 481(a)
adjustment for this change is zero. Under its present
method of accounting and under the NGSH Method
(proposed method of accounting), X properly capital-
ized 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 distri-
bution 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 Fed-
eral 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

Bulletin No. 2023–18 825 May 1, 2023
deducted $3 million for the cost of the replacements
under § 162(a). Y files a Form 3115 with its Federal
income tax return for Year 2 to change its method
of accounting to use the NGSH Method described in
Rev. Proc. 2023-15.
(ii) Because Y filed its method change for Year 2,
section 5.08(2)(a)(i) of Rev. Proc. 2023-15 applies
to this change. However, the special rule under sec-
tion 5.08(3)(a) of Rev. Proc. 2023-15 would apply
only if Y had filed its method change for Year 1.
Accordingly, section 5.05(1)(g) and (h) of Rev. Proc.
2023-15 apply to the replacement cost of $12 million
that Y deducted under § 162(a) on its Federal income
tax returns before Year 1, and to the replacement cost
of $3 million that Y deducted under § 162(a) on its
Federal income tax return for Year 1. Therefore, the
total cost of $15 million for these replacements is a
per se capital expenditure, and must be capitalized,
under the NGSH Method.
(iii) At the beginning of Year 2, Y is treated
under Rev. Proc. 2023-15 as owning natural gas
distribution property at a cost of $123 million ($120
million - $10 million + $12 million - $2 million +
$3 million). Under section 5.08(2)(a)(i) of Rev. Proc.
2023-15, Y must make a late general asset account
election on its Form 3115 to include in general asset
accounts all of the $123 million of natural gas distri-
bution 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 begin-
ning balances of the depreciation reserves. The late
general asset account election change is made on a
modified cut-off method and, therefore, a § 481(a)
adjustment is neither required nor permitted for the
late general asset account election.
(iv) On its Form 3115 to change to the NGSH
Method of Rev. Proc. 2023-15, the net positive
§ 481(a) adjustment for this change is $14 million
($15 million for the cost of the replacements before
Year 2 less depreciation allowed or allowable of $1
million for such replacement assets before Year 2)
and is taken into account in computing Y’s income
in the manner provided in section 3.12(4)(a) of this
revenue procedure.
(d) Example 4. (i) Z is a local natural gas distri-
bution company. Before Year 4, Z owned and placed
in service natural gas distribution property at a cost
of $150 million before any dispositions or additions.
Before Year 4, Z replaced parts of such property that
had an original cost of $30 million and incurred $45
million for the cost of such replacements. On its Fed-
eral 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 depre-
ciation of $15 million on such $45 million. Z files
a Form 3115 with its Federal income tax return for
Year 4 to change its method of accounting to use the
NGSH Method described in Rev. Proc. 2023-15.
Assume Z is eligible to file Form 3115 for Year 4
under the automatic change procedures in Rev. Proc.
2015-13.
(ii) At the beginning of Year 4, Z owns natural
gas distribution property at a cost of $165 million
($150 million - $30 million + $45 million). Because
Year 4 is Z’s fourth taxable year ending after May 1,
2023, sections 5.08(2)(a)(iii) and 5.08(3)(b) of Rev.
Proc. 2023-15 apply. Accordingly, under section
5.08(2)(a)(iii) of Rev. Proc. 2023-15, Z must make a
late general asset account election on its Form 3115
to include in general asset accounts all of the $165
million of natural gas distribution property that Z
owns at the beginning of Year 4. These general asset
accounts also must include the total depreciation
allowed or allowable before the beginning of Year
4 for such property as the beginning balances of the
depreciation reserves. The late general asset account
election change is made using a modified cut-off
method and, therefore, a § 481(a) adjustment is nei-
ther permitted nor required for the late general asset
account election.
(iii) Because sections 5.08(2)(a)(iii) and 5.08(3)
(b) of Rev. Proc. 2023-15 apply, Z’s change to the
NGSH Method described in Rev. Proc. 2023-15,
applies only to natural gas transmission and distri-
bution property expenditures paid or incurred by Z
beginning in Year 4 and is made on a cut-off basis.
Therefore, a § 481(a) adjustment is neither required
nor permitted for the change to the NGSH Method
described in Rev. Proc. 2023-15.
(e) Example 5. (i) The facts are the same as
in Example 4 except that, on its Federal income
tax returns before Year 4, Z improperly deducted
$45 million for the cost of the replacements under
§ 162(a). Such $45 million of replacement costs
should have been capitalized under § 263(a). If Z
had capitalized the $45 million for the cost of the
replacements, the total depreciation allowed or
allowable for such assets would have been $15 mil-
lion before Year 4.
(ii) Because Year 4 is Z’s fourth taxable year end-
ing 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 replace-
ments incurred before Year 4. The net positive
§ 481(a) adjustment for this coordinating change is
$30 million ($45 million for the cost of the replace-
ments before Year 4 less depreciation allowed or
allowable of $15 million for such replacement assets
before Year 4). Z takes this net positive § 481(a)
adjustment of $30 million into account in computing
Z’s taxable income in the manner provided in section
3.12(4)(a) of this revenue procedure.
(iii) Z owns natural gas distribution property at
a cost of $165 million ($150 million - $30 million +
$45 million) at the beginning of Year 4. Accordingly,
Z must make a late general asset account election on
its Form 3115 to include in general asset accounts
all of the $165 million of natural gas distribution
property that Z owns at the beginning of Year 4.
These general asset accounts also must include the
total depreciation allowed or allowable before the
beginning of Year 4 for such property as the begin-
ning 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 distri-
bution property expenditures paid or incurred by Z
beginning in Year 4 and is made on a cut-off basis.
Therefore, a § 481(a) adjustment is neither required
nor permitted for the change to the NGSH Method
described in Rev. Proc. 2023-15.
(v) Pursuant to section 3.12(6)(c) and section
5.08(3)(b) of Rev. Proc. 2023-15 the change to
capitalize the replacement costs of $45 million, the
late general asset account election change, and the
change to use the NGSH Method provided under
Rev. Proc. 2023-15 must be included on the same
Form 3115 filed by Z for Year 4.
(8) Designated automatic accounting
method change number. The designated
automatic accounting method change
number for a change to the methods of
accounting under this section 3.12 is
“269.”
(9) Contact information. For further
information regarding a change under this
section, contact Hyowon Lee or Merrill
Feldstein at (202) 317-5100 (not a toll-
free call).
SECTION 7. EFFECT ON OTHER
DOCUMENTS
.01 Section 3.12 of Rev. Proc. 2022-
14 is modified to include the accounting
method changes in this revenue procedure.
.02 Rev. Proc. 2011-42 is amplified.
SECTION 8. EFFECTIVE DATE
This revenue procedure is effective for
taxable years ending after May 1, 2023.
SECTION 9. PAPERWORK
REDUCTION ACT
The collection of information con-
tained in this revenue procedure has been
submitted to the Office of Management
and Budget for review under OMB con-
trol 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 dis-
plays 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.

May 1, 2023 826 Bulletin No. 2023–18
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 Account-
ing). For further information regarding
this revenue procedure, contact Hyowon
Lee or Merrill Feldstein at 202-317-5100
(not a toll-free number).

Bulletin No. 2023–18 827 May 1, 2023
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 prop-
erty 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 liquefac-
tion 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 compo-
nents 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 miscella-
neous equipment) are excluded from this
revenue procedure and are determined
under §§ 263(a), 263A, and other applica-
ble authority.
.02 Instrumentation and controls. In
general, instrumentation and controls
are a major component of the unit of
property they monitor or control. How-
ever, 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 sep-
arate units of property (for example,
meters and regulators).
.03 Scope. This Appendix A does not
apply to determine the units of property
of non-linear property or the major com-
ponents 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 pipe-
line gas quality at the station, including
the following major components:
(a) Each scrubber.
(b) Each filter separator.
(c) Each separator.
(d) Each dehydrator (also referred to as
a dryer).
(e) Each chromatograph.
(f) Each continuous gas sampler.
(g) Each water vapor monitor.
(h) Each sulfur removal apparatus.
(i) Each cooler.
(j) Each heater.
(9) All the electric supply equipment at
the station, including the following major
components:
(a) Each generator, including motor.
(b) Each set of batteries and charger.
(c) Each transformer.
(d) Each power supply (for example, a
variable frequency drive).
(e) All other electric supply devices,
including switchgear.
(10) All the odorizing equipment at
the station, including the following major
components:
(a) All the equipment to inject an odor-
ant 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, includ-
ing pad, walls, and roof.
(14) All fencing, walls, enclosures, and
miscellaneous structures or land improve-
ments that are not capitalized to the land
surrounding a compressor station and any
miscellaneous pads.
(15) Each parcel of land and each ease-
ment or other right to land.
.02 Gas storage facility property. At a
gas storage facility, the units of property
are the following:
(1) Each tank.
(2) Each well, including the following
major components:
(a) The wellhead.
(b) The casing.
(3) Each compressor, including prime
mover.
(4) Each meter.
(5) Each regulator.
(6) Each flaring or incinerating system,
including stack.
(7) All the lines at the facility, includ-
ing header, pipe, coatings, fittings, valves,
and cathodic protection.
(8) All the equipment to maintain pipe-
line quality gas at the facility, including
the following major components:
(a) Each scrubber.
(b) Each filter separator.
(c) Each separator.
(d) Each dehydrator (also referred to as
a dryer).
(e) Each chromatograph.
(f) Each continuous gas sampler.
(g) Each water vapor monitor.
(h) Each sulfur removal apparatus.
(i) Each cooler.
(j) Each heater.
(9) All the odorizing equipment at the
facility, including the following major
components:
(a) All the equipment to inject an odor-
ant 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).

May 1, 2023 828 Bulletin No. 2023–18
(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, includ-
ing pad, walls, and roof.
(14) All the fencing, walls, enclosures,
and/or miscellaneous structures surround-
ing the facility and any miscellaneous
pads.
(15) Each parcel of land and each ease-
ment or other right to land.
.03 Measuring and regulating station
property. At a measuring and regulat-
ing station, including a city gate station,
the units of non-linear property are the
following:
(1) Each meter.
(2) Each regulator.
(3) All the lines at the station, including
header, pipe, coatings, fittings, valves, and
cathodic protection.
(4) All the equipment to maintain pipe-
line 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 odor-
ant 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 ease-
ment or other right to land.
.04 Meters and regulators. Each meter
and each regulator not described in sec-
tions 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.

Bulletin No. 2023–18 829 May 1, 2023
APPENDIX B—EXTRAPOLATION
GUIDANCE
SECTION 1. INTRODUCTION
.01 In general. This Appendix B pro-
vides an extrapolation methodology that
an eligible taxpayer may use in connec-
tion 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 pro-
vided 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) adjust-
ment. Generally, the taxpayer first applies
the method to a testing period of recent,
representative years and derives an aver-
age repair deduction under the method
of accounting as a percentage of total
capital additions for financial accounting
purposes. This percentage, adjusted by
a reduction percentage that varies based
on time, is then applied to the adjusted
capital additions for financial account-
ing purposes for prior years for which
extrapolation is used to derive a deemed
§ 481(a) adjustment amount for each
year. These extrapolated § 481(a) adjust-
ment amounts are then combined with
the actual adjustment amounts for years
in which the § 481(a) adjustment is cal-
culated 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 cal-
culation 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 tax-
able year preceding the year of change.
Alternatively, a taxpayer may choose the
year of change as the final year of the test-
ing 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, includ-
ing acquisitions and dispositions as well
as any other events that resulted in signifi-
cant 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 representa-
tive, the taxpayer must exclude data from
the non-representative year from the test-
ing 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 extrap-
olation 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 addi-
tional testing years must be consecutive
years that immediately precede the origi-
nal 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-representa-
tive year.
(2) Repair deduction percentage. Sec-
ond, a repair deduction percentage for
each year for which extrapolation is used
(extrapolation year) is computed as fol-
lows, using data from the testing period.
(a) Repair deductions during the test-
ing 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 per-
centage. The sum of the repair expenses
allowable as deductions for all testing
years in the testing period, as determined
under section 2.02(2)(a) of this Appendix
B, is then divided by the sum of all capi-
tal 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 prop-
erly 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 extrap-
olation 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 ten-
tative 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 extrapola-
tion year.

May 1, 2023 830 Bulletin No. 2023–18
(a) The repair deduction amount for an
extrapolation year is calculated by mul-
tiplying 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 extrapola-
tion year.
(b) In determining the repair deduc-
tion amount for an extrapolation year, a
taxpayer must account for any book-tax
basis adjustments for property placed in
service in the extrapolation year. Book-
tax basis adjustments for property placed
in service in the extrapolation year may be
accounted for by multiplying the tentative
repair deduction amount for an extrapo-
lation year by the taxpayer’s book-to-tax
adjustment percentage for the extrapola-
tion 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 adjust-
ments 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 nat-
ural gas transmission property or natural
gas distribution property, taxpayers must
use a method comparable to the method
actually used to allocate qualified repair
expenditures to repair allowance property
for that year. For example, if in applying
§ 1.167(a)-11(d)(2) for the 1997 taxable
year a taxpayer determined that 73 percent
of its 1997 qualified repair expenditures
for natural gas transmission and natural
gas distribution property were attribut-
able 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 sub-
tracting 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) adjust-
ment 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 taxpay-
er’s proposed method of accounting. For
instance, if under the proposed method a
taxpayer’s repair deduction for an extrapo-
lation year would be tentatively increased
by $1,000, such that the unadjusted basis
of the property placed in service would be
correspondingly decreased by $1,000, the
$1,000 tentative repair deduction increase
for the extrapolation year must be reduced
by the portion of the $1,000 in unadjusted
basis that the taxpayer had recovered prior
to the year of change.
(7)
Total § 481(a) adjustment. Finally,
the total § 481(a) adjustment attributable
to the change to the taxpayer’s proposed
method of accounting is determined. The
total § 481(a) adjustment for the year
of change is calculated by combining
the § 481(a) adjustment amounts for all
extrapolation years, as described in this
section 2.02 of this Appendix B, with
the adjustment amounts, after taking into
account book-tax basis adjustments, for
years determined under § 481(a) in the
normal manner.
.03 Example. In 2023, W, a calen-
dar 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 deter-
mine the amount of its § 481(a) adjustment
attributable to taxable years 2003 through
2019.
Following the general rule in section
2.02(1) of this Appendix B, W uses as its
testing period 2020, 2021, and 2022, the
three consecutive taxable years ending
with 2022, the year preceding the year of
change. Assume that each of 2020, 2021,
and 2022 are representative of all years
included in W
’s § 481(a) adjustment.
W’s book capital additions for 2020,
2021, and 2022 are $3,000, $3,000,
and $4,000, respectively, for a total of
$10,000. Of these amounts, the por-
tions that are properly treated as repair
expenses allowable as deductions result-
ing from the application of W’s proposed
method of accounting for 2020, 2021,
and 2022, before taking into account
book-tax basis adjustments, are $300,
$400, and $300, respectively, for a total
of $1,000.
For its 2014 extrapolation year, W’s
book capital additions were $3,333. W’s
book-to-tax adjustment percentage for
2014 is 90 percent. In 2013, W elected
to apply the ADR repair allowance under
§ 1.167(a)-11(d)(2), which applied to 25
percent of W’s natural gas transmission and
natural gas distribution property. Under
W’s prior method of accounting (prior
to application of the NGSH Method), W
deducted $150 in repair expenses in 2014.
W determines its § 481(a) adjustment
for 2014 as follows:
Step 1. W determines that it will use
taxable years 2020, 2021, and 2022 as the
testing years in its testing period.
Step 2. W calculates its repair deduc-
tion percentage for each extrapolation
year. First, a tentative repair deduction
percentage is calculated using data from

Bulletin No. 2023–18 831 May 1, 2023
the testing period (taxable years 2020,
2021, and 2022). Book capital addi-
tions that are properly treated as repair
expenses allowable as deductions result-
ing from the application of the proposed
method of accounting, before taking into
account book-tax basis adjustments, for
2020, 2021, and 2022, the testing years
that comprise the testing period, equal
$1,000 ($300 + $400 + $300). Total book
capital additions for the testing period are
$10,000 ($3,000 + $3,000 + $4,000). W’s
tentative repair deduction percentage is 10
percent ($1,000 / $10,000).
Next, W calculates the reduction per-
centage for each extrapolation year using
the formula (1 - (0.10 * (X/Y))), where X
equals the number of years the extrapo-
lation year precedes 2022, the final year
of the testing period, and Y equals 3, the
number of years in the testing period
(2020-2022). The reduction percentage
for each extrapolation year is calculated
as follows:
Extrapolation Year
Reduction Percentage Calculation
(Step A)
Reduction Percentage Calculation
(Step B)
20190.10 * (3/3) = 0.101 – 0.10 = 0.90 = 90.0%
2018
0.10 * (4/3) = 0.1331 – 0.133 = 0.867 = 86.7%
20170.10 * (5/3) = 0.1671 – 0.167 = 0.833 = 83.3%
2016
0.10 * (6/3) = 0.201 – 0.20 = 0.80 = 80.0%
20150.10 * (7/3) = 0.2331 – 0.233 = 0.767 = 76.7%
2014
0.10 * (8/3) = 0.2671 – 0.267 = 0.733 = 73.3%
20130.10 * (9/3) = 0.301 – 0.30 = 0.70 = 70.0%
20120.10 * (10/3) = 0.3331 – 0.333 = 0.667 = 66.7%
20110.10 * (11/3) = 0.3671 – 0.367 = 0.633 = 63.3%
20100.10 * (12/3) = 0.401 – 0.40 = 0.60 = 60.0%
20090.10 * (13/3) = 0.4331 – 0.433 = 0.567 = 56.7%
20080.10 * (14/3) = 0.4671 – 0.467 = 0.533 = 53.3%
20070.10 * (15/3) = 0.501 – .50 = 0.50 = 50.0%
20060.10 * (16/3) = 0.5331 – 0.533 = 0.467 = 46.7%
20050.10 * (17/3) = 0.5671 – 0.567 = 0.433 = 43.3%
20040.10 * (18/3) = 0.601 – 0.60 = 0.40 = 40.0%
20030.10 * (19/3) = 0.6331 – 0.633 = 0.367 = 36.7%
Finally, W multiplies the tentative
repair deduction percentage for each
extrapolation year by the reduction per-
centage 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 per-
cent = 7.33 percent).
Step 3. Next, W calculates a tentative
repair deduction amount for each extrapo-
lation 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), result-
ing 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), yield-
ing 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 deduc-
tion 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). There-
fore, W’s § 481(a) adjustment amount for
2014 is negative $15.
Step 6. To determine its § 481(a) adjust-
ment 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

May 1, 2023 832 Bulletin No. 2023–18
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 Appen-
dix B (as described above for 2014),
with the § 481(a) adjustments attribut-
able 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.

Bulletin No. 2023–18 833 May 1, 2023
Part IV
Announcement of
Disciplinary Sanctions
From the Office of
Professional Responsibility
Announcement 2023-13
The Office of Professional Responsibil-
ity (OPR) announces recent disciplinary
sanctions involving attorneys, certified pub-
lic accountants, enrolled agents, enrolled
actuaries, enrolled retirement plan agents,
appraisers, and unenrolled/unlicensed
return preparers (individuals who are not
enrolled to practice and are not licensed as
attorneys or certified public accountants).
Licensed or enrolled practitioners are sub-
ject to the regulations governing practice
before the Internal Revenue Service (IRS),
which are set out in Title 31, Code of Fed-
eral Regulations, Subtitle A, Part 10, and
which are released as Treasury Department
Circular No. 230. The regulations prescribe
the duties and restrictions relating to such
practice and prescribe the disciplinary
sanctions for violating the regulations.
Unenrolled/unlicensed return preparers are
subject to Revenue Procedure 81-38 and
superseding guidance in Revenue Proce-
dure 2014-42, which govern a preparer’s
eligibility to represent taxpayers before the
IRS in examinations of tax returns the pre-
parer both prepared for the taxpayer and
signed as the preparer. Additionally, unen-
rolled/unlicensed return preparers who
voluntarily participate in the Annual Filing
Season Program under Revenue Procedure
2014-42 agree to be subject to the duties
and restrictions in Circular 230, including
the restrictions on incompetent or disrepu-
table conduct.
The disciplinary sanctions to be
imposed for violation of the applicable
standards are:
Disbarred from practice before the
IRS—An individual who is disbarred
is not eligible to practice before the IRS
as defined at 31 C.F.R. § 10.2(a)(4) for a
minimum period of five (5) years.
Suspended from practice before the
IRS—An individual who is suspended is
not eligible to practice before the IRS as
defined at 31 C.F.R. § 10.2(a)(4) during
the term of the suspension.
Censured in practice before the
IRS—Censure is a public reprimand.
Unlike disbarment or suspension, censure
does not affect an individual’s eligibility
to practice before the IRS, but OPR may
subject the individual’s future practice
rights to conditions designed to promote
high standards of conduct.
Monetary penalty—A monetary pen-
alty may be imposed on an individual who
engages in conduct subject to sanction,
or on an employer, firm, or entity if the
individual was acting on its behalf and it
knew, or reasonably should have known,
of the individual’s conduct.
Disqualification of appraiser—An
appraiser who is disqualified is barred
from presenting evidence or testimony in
any administrative proceeding before the
Department of the Treasury or the IRS.
Ineligible for limited practice—An
unenrolled/unlicensed return preparer
who fails to comply with the requirements
in Revenue Procedure 81-38 or to comply
with Circular 230 as required by Revenue
Procedure 2014-42 may be determined
ineligible to engage in limited practice as
a representative of any taxpayer.
Under the regulations, individuals
subject to Circular 230 may not assist, or
accept assistance from, individuals who
are suspended or disbarred with respect
to matters constituting practice (i.e., rep-
resentation) before the IRS, and they may
not aid or abet suspended or disbarred
individuals to practice before the IRS.
Disciplinary sanctions are described in
these terms:
Disbarred by decision, Suspended by
decision, Censured by decision, Mone-
tary penalty imposed by decision, and
Disqualified after hearing—An adminis-
trative law judge (ALJ) issued a decision
imposing one of these sanctions after the
ALJ either (1) granted the government’s
summary judgment motion or (2) con-
ducted an evidentiary hearing upon OPR’s
complaint alleging violation of the regula-
tions. After 30 days from the issuance of
the decision, in the absence of an appeal,
the ALJ’s decision becomes the final
agency decision.
Disbarred by default decision, Sus-
pended by default decision, Censured
by default decision, Monetary penalty
imposed by default decision, and Dis-
qualified by default decision—An ALJ,
after finding that no answer to OPR’s com-
plaint was filed, granted OPR’s motion for
a default judgment and issued a decision
imposing one of these sanctions.
Disbarment by decision on appeal,
Suspended by decision on appeal,
Censured by decision on appeal, Mon-
etary penalty imposed by decision on
appeal, and Disqualified by decision
on appeal—The decision of the ALJ was
appealed to the agency appeal authority,
acting as the delegate of the Secretary
of the Treasury, and the appeal authority
issued a decision imposing one of these
sanctions.
Disbarred by consent, Suspended by
consent, Censured by consent, Mone-
tary penalty imposed by consent, and
Disqualified by consent—In lieu of a
disciplinary proceeding being instituted
or continued, an individual offered a con-
sent to one of these sanctions and OPR
accepted the offer. Typically, an offer of
consent will provide for: suspension for
an indefinite term; conditions that the indi-
vidual must observe during the suspension;
and the individual’s opportunity, after a
stated number of months, to file with OPR
a petition for reinstatement affirming com-
pliance with the terms of the consent and
affirming current fitness and eligibility to
practice (i.e., an active professional license
or active enrollment status, with no inter-
vening violations of the regulations).
Suspended indefinitely by decision in
expedited proceeding, Suspended indef-
initely by default decision in expedited
proceeding, Suspended by consent in
expedited proceeding—OPR instituted
an expedited proceeding for suspension
(based on certain limited grounds, includ-
ing loss of a professional license for cause,
and criminal convictions).
Determined ineligible for limited
practice---There has been a final deter-
mination that an unenrolled/unlicensed
return preparer is not eligible for limited
representation of any taxpayer because the
preparer violated standards of conduct or

May 1, 2023 834 Bulletin No. 2023–18
failed to comply with any of the require-
ments to act as a representative.
A practitioner who has been disbarred
or suspended under 31 C.F.R. § 10.60, or
suspended under § 10.82, or a disqualified
appraiser may petition for reinstatement
before the IRS after the expiration of 5
years following such disbarment, suspen-
sion, or disqualification (or immediately
following the expiration of the suspension
or disqualification period if shorter than 5
years). Reinstatement will not be granted
unless the IRS is satisfied that the peti-
tioner is not likely to engage thereafter in
conduct contrary to Circular 230, and that
granting such reinstatement would not be
contrary to the public interest.
Reinstatement decisions are published
at the individual’s request, and described
in these terms:
Reinstated to practice before the
IRS---The individual’s petition for
reinstatement has been granted. The
agent, and eligible to practice before the
IRS, or in the case of an appraiser, the
individual is no longer disqualified.
Reinstated to engage in limited
practice before the IRS---The individ-
ual’s petition for reinstatement has been
granted. The individual is an unenrolled/
unlicensed return preparer and eligible to
engage in limited practice before the IRS,
subject to requirements the IRS has pre-
scribed for limited practice by tax return
preparers.
OPR has authority to disclose the
grounds for disciplinary sanctions in these
situations: (1) an ALJ or the Secretary’s del-
egate on appeal has issued a final decision;
(2) the individual has settled a disciplinary
case by signing OPR’s “consent to sanc-
tion” agreement admitting to one or more
violations of the regulations and consenting
to the disclosure of the admitted violations
(for example, failure to file Federal income
tax returns, lack of due diligence, conflict of
interest, etc.); (3) OPR has issued a decision
in an expedited proceeding for indefinite
suspension; or (4) OPR has made a final
determination (including any decision on
appeal) that an unenrolled/unlicensed return
preparer is ineligible to represent any tax-
payer before the IRS.
Announcements of disciplinary sanc-
tions appear in the Internal Revenue
Bulletin at the earliest practicable date.
The sanctions announced below are alpha-
betized first by state and second by the last
names of the sanctioned individuals.
City & StateNameProfessional
Designation
Disciplinary SanctionEffective Date(s)
Indiana
Beech GroveJohnson, Curtis L.C PASuspended by default decision
in expedited proceeding under
31 C.F.R. § 10.82(b)
Indefinite from
March 21, 2023
Louisiana
MandevilleSilva, Brent A.C PASuspended by default decision
in expedited proceeding under
31 C.F.R. § 10.82(b)
Indefinite from
February 14, 2023
North Carolina
LawndaleSpangler, Janice C.C PASuspended by default decision
in expedited proceeding under
31 C.F.R. § 10.82(b)
Indefinite from
March 21, 2023
Virginia
Falls ChurchRoberts, Margot E.AttorneySuspended by default decision
in expedited proceeding
under 31 C.F.R. § 10.82(b)
Indefinite from
March 21, 2023

Bulletin No. 2023–18 i May 1, 2023
Definition of Terms
Revenue rulings and revenue procedures
(hereinafter referred to as “rulings”) that
have an effect on previous rulings use the
following defined terms to describe the
effect:
Amplified describes a situation where
no change is being made in a prior pub-
lished position, but the prior position is
being extended to apply to a variation of
the fact situation set forth therein. Thus, if
an earlier ruling held that a principle ap-
plied to A, and the new ruling holds that
the same principle also applies to B, the
earlier ruling is amplified. (Compare with
modified, below).
Clarified is used in those instances
where the language in a prior ruling is be-
ing made clear because the language has
caused, or may cause, some confusion. It
is not used where a position in a prior rul-
ing is being changed.
Distinguished describes a situation
where a ruling mentions a previously pub-
lished ruling and points out an essential
difference between them.
Modified is used where the substance
of a previously published position is being
changed. Thus, if a prior ruling held that a
principle applied to A but not to B, and the
new ruling holds that it applies to both A
and B, the prior ruling is modified because
it corrects a published position. (Compare
with amplified and clarified, above).
Obsoleted describes a previously pub-
lished ruling that is not considered deter-
minative with respect to future transactions.
This term is most commonly used in a ruling
that lists previously published rulings that
are obsoleted because of changes in laws or
regulations. A ruling may also be obsoleted
because the substance has been included in
regulations subsequently adopted.
Revoked describes situations where the
position in the previously published ruling
is not correct and the correct position is
being stated in a new ruling.
Superseded describes a situation where
the new ruling does nothing more than
restate the substance and situation of a
previously published ruling (or rulings).
Thus, the term is used to republish under
the 1986 Code and regulations the same
position published under the 1939 Code
and regulations. The term is also used
when it is desired to republish in a single
ruling a series of situations, names, etc.,
that were previously published over a
period of time in separate rulings. If the
new ruling does more than restate the sub-
stance of a prior ruling, a combination of
terms is used. For example, modified and
superseded describes a situation where the
substance of a previously published ruling
is being changed in part and is continued
without change in part and it is desired to
restate the valid portion of the previous-
ly published ruling in a new ruling that is
self contained. In this case, the previously
published ruling is first modified and then,
as modified, is superseded.
Supplemented is used in situations in
which a list, such as a list of the names of
countries, is published in a ruling and that
list is expanded by adding further names
in subsequent rulings. After the original
ruling has been supplemented several
times, a new ruling may be published that
includes the list in the original ruling and
the additions, and supersedes all prior rul-
ings in the series.
Suspended is used in rare situations to
show that the previous published rulings
will not be applied pending some future
action such as the issuance of new or
amended regulations, the outcome of cas-
es in litigation, or the outcome of a Ser-
vice study.
Abbreviations
The following abbreviations in current
use and formerly used will appear in
material published in the Bulletin.
A—Individual.
Acq.—Acquiescence.
B—Individual.
BE—Beneficiary.
BK—Bank.
B.T.A.—Board of Tax Appeals.
C—Individual.
C.B.—Cumulative Bulletin.
CFR—Code of Federal Regulations.
CI
—City.
COOP—Cooperative.
Ct.D.—Court Decision.
CY—County.
D—Decedent.
DC—Dummy Corporation.
DE—Donee.
Del. Order—Delegation Order.
DISC—Domestic International Sales Corporation.
DR—Donor.
E—Estate.
EE—Employee.
E.O.—Executive Order.
ER—Employer.
ERISA—Employee Retirement Income Security Act.
EX—Executor.
F—Fiduciary.
FC—Foreign Country.
FICA—Federal Insurance Contributions Act.
FISC—Foreign International Sales Company.
FPH—Foreign Personal Holding Company.
F.R.—Federal Register.
FUTA—Federal Unemployment Tax Act.
FX—Foreign corporation.
G.C.M.—Chief Counsel’s Memorandum.
GE—Grantee.
GP—General Partner.
GR—Grantor.
IC—Insurance Company.
I.R.B.—Internal Revenue Bulletin.
LE—Lessee.
LP—Limited Partner.
LR—Lessor.
M—Minor.
Nonacq.—Nonacquiescence.
O—Organization.
P—Parent Corporation.
PHC—Personal Holding Company.
PO—Possession of the U.S.
PR—Partner.
PRS—Partnership.
PTE—Prohibited Transaction Exemption.
Pub. L.—Public Law.
REIT—Real Estate Investment Trust.
Rev. Proc.—Revenue Procedure.
Rev. Rul.—Revenue Ruling.
S—Subsidiary.
S.P.R.—Statement of Procedural Rules.
Stat.—Statutes at Large.
T—Target Corporation.
T.C.—Tax Court.
T.D.—Treasury Decision.
TFE—Transferee.
TFR—Transferor.
T.I.R.—Technical Information Release.
TP—Taxpayer.
TR—Trust.
TT—Trustee.
U.S.C.—United States Code.
X—Corporation.
Y—Corporation.
Z—Corporation.

May 1, 2023 ii Bulletin No. 2023–18
Numerical Finding List
1
Bulletin 2023–18
Announcements:
2023-2, 2023-2 I.R.B. 344
2023-1, 2023-3 I.R.B. 422
2023-3, 2023-5 I.R.B. 447
2023-4, 2023-7 I.R.B. 470
2023-5, 2023-9 I.R.B. 499
2023-6, 2023-9 I.R.B. 501
2023-8, 2023-14 I.R.B. 632
2023-9, 2023-15 I.R.B. 639
2023-10, 2023-16 I.R.B. 663
2023-7, 2023-17 I.R.B. 797
2023-11, 2023-17 I.R.B. 798
2023-12, 2023-17 I.R.B. 799
2023-13, 2023-18 I.R.B. 833
AOD:
2023-1, 2023-10 I.R.B. 502
2023-2, 2023-11 I.R.B. 529
Notices:
2023-4, 2023-2 I.R.B. 321
2023-5, 2023-2 I.R.B. 324
2023-6, 2023-2 I.R.B. 328
2023-8, 2023-2 I.R.B. 341
2023-1, 2023-3 I.R.B. 373
2023-2, 2023-3 I.R.B. 374
2023-3, 2023-3 I.R.B. 388
2023-7, 2023-3 I.R.B. 390
2023-9, 2023-3 I.R.B. 402
2023-10, 2023-3 I.R.B. 403
2023-11, 2023-3 I.R.B. 404
2023-12, 2023-6 I.R.B. 450
2023-13, 2023-6 I.R.B. 454
2023-16, 2023-8 I.R.B. 479
2023-17, 2023-10 I.R.B. 505
2023-18, 2023-10 I.R.B. 508
2023-20, 2023-10 I.R.B. 523
2023-19, 2023-11 I.R.B. 560
2023-21, 2023-11 I.R.B. 563
2023-22, 2023-12 I.R.B. 569
2023-23, 2023-13 I.R.B. 571
2023-24, 2023-13 I.R.B. 571
2023-26, 2023-13 I.R.B. 577
2023-25, 2023-14 I.R.B. 629
2023-27, 2023-15 I.R.B. 634
2023-28, 2023-15 I.R.B. 635
2023-31, 2023-16 I.R.B. 661
2023-30, 2023-17 I.R.B. 766
2023-33, 2023-18 I.R.B. 803
Proposed Regulations:
REG-100442-22, 2023-3 I.R.B. 423
REG-146537-06, 2023-3 I.R.B. 436
Proposed Regulations:—Continued
REG-114666-22, 2023-4 I.R.B. 437
REG 122286-18, 2023-11 I.R.B. 565
REG-120653-22, 2023-15 I.R.B. 640
REG-105954-22, 2023-16 I.R.B. 713
REG-120080-22, 2023-16 I.R.B. 746
REG 109309-22, 2023-17 I.R.B. 770
REG 121709-19, 2023-17 I.R.B. 789
Revenue Procedures:
2023-1, 2023-1 I.R.B. 1
2023-2, 2023-1 I.R.B. 120
2023-3, 2023-1 I.R.B. 144
2023-4, 2023-1 I.R.B. 162
2023-5, 2023-1 I.R.B. 265
2023-7, 2023-1 I.R.B. 305
2023-8, 2023-3 I.R.B. 407
2023-10, 2023-3 I.R.B. 411
2023-11, 2023-3 I.R.B. 417
2023-14, 2023-6 I.R.B.
466
2023-9, 2023-7 I.R.B. 471
2023-13, 2023-13 I.R.B. 581
2023-17, 2023-13 I.R.B. 604
2023-18, 2023-13 I.R.B. 605
2023-19, 2023-13 I.R.B. 626
2023-20, 2023-15 I.R.B. 636
2023-12, 2023-17 I.R.B. 768
2023-15, 2023-18 I.R.B. 806
Revenue Rulings:
2023-1, 2023-2 I.R.B. 309
2023-3, 2023-6 I.R.B. 448
2023-4, 2023-9 I.R.B. 480
2023-5, 2023-10 I.R.B. 503
2023-6, 2023-14 I.R.B. 627
2023-7, 2023-15 I.R.B. 633
2023-2, 2023-16 I.R.B. 658
2023-8, 2023-18 I.R.B. 801
Treasury Decisions:
9970, 2023-2 I.R.B. 311
9771, 2023-3 I.R.B. 346
9772, 2023-11 I.R.B. 530
9773, 2023-11 I.R.B. 557
1
A cumulative list of all revenue rulings, revenue procedures, Treasury decisions, etc., published in Internal Revenue Bulletins 2022–27 through 2022–52 is in Internal Revenue Bulletin
2022–52, dated December 27, 2022.

Bulletin No. 2023–18 iii May 1, 2023
Finding List of Current Actions on
Previously Published Items
1
Bulletin 2023–18
1
A cumulative list of all revenue rulings, revenue procedures, Treasury decisions, etc., published in Internal Revenue Bulletins 2022–27 through 2022–52 is in Internal Revenue Bulletin
2022–52, dated December 27, 2022.

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