# Bulletin No. 2023–18

> Briefs, arguments, decisions, and more.

URL: https://www.frixlaw.com/law-library/documents/agency%3Airs%3Af2a0f412d3dd4fb0

## Record

- **Collection:** Agency decision
- **Document type:** Agency decision

## Text

HIGHLIGHTS
OF THIS ISSUE




Bulletin No. 2023–18
May 1, 2023

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 individuals 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 restrictions 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 capitalized. To apply this safe harbor method, a taxpayer must first
classify its natural gas transmission and distribution property as either linear property (for example, pipe, fittings,
and valves) or non-linear property (for example, compressors, 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

Finding Lists begin on page ii.

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 experimental 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 experimental expenditures, when it deducted other research or
experimental expenditures, constituted a method of accounting or an error.

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 official 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 application 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, statements 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 rulings 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, disbarment 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 expenditures; 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), commonly referred to as the Tax Cuts and Jobs
Act (TCJA), amended § 174 of the Internal 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 December 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 taxpayer 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 taxpayer 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 expenditures 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 further provides that the additional research
or experimental expenditures cannot be
treated as deferred and amortized under
former § 174(b) or chargeable to capital account and subsequently amortized
or written off upon abandonment of the
project or projects because the Commissioner’s consent to change a method of
accounting was not obtained. Accordingly, 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 experimental expenditures (for amounts paid or
incurred in taxable years beginning after
December 31, 2021) to be charged to capital 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) beginning 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 former § 174.

Pursuant to the authority provided
under § 301.7805-1 of the Procedure
and Administration Regulations, the
Treasury Department and the IRS periodically 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 statute, regulation, or subsequent published
position; or (3) the facts set forth no longer 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 experimental 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 consistently 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 deviation 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 treatment of amounts paid or incurred for
research or experimentation expenditures
constitutes a change in method of accounting 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-

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.
1

Bulletin No. 2023–18

801

May 1, 2023

sioner to change a method of accounting.
See § 446(e), former § 174(a)(3), § 1.1743(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); Diebold 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 applicable, 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. 202214. For these reasons, Rev. Rul. 58-74 is
no longer determinative.

May 1, 2023

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-

802

able year or years, and (3) timely filing the
claim for refund, amended return, or AAR
not later than July 31, 2023. The eligibility 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 appropriate. 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).

Bulletin No. 2023–18

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 average segment rates under § 430(h)(2) of the
Internal Revenue Code. In addition, this
notice provides guidance as to the interest 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 single-employer plans (except for CSEC plans

Applicable Month
April 2023

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 specified 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 election 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. Consistent 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 segment 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 percentages 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
First Segment
Second Segment
2.68
3.93

The adjusted 24-month average segment 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

Third Segment
4.12

the corresponding 25-year average segment 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 In

Applicable Month

First Segment

Second Segment

Third Segment

2022

April 2023

4.75

5.18

5.92

2023

April 2023

4.75

5.00

5.74

30-YEAR TREASURY SECURITIES
INTEREST RATES
Section 431 specifies the minimum funding requirements that apply

to multiemployer plans pursuant to
§ 412. Section 431(c)(6)(B) specifies
a minimum amount for the full-funding 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

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)).
1

Bulletin No. 2023–18

803

May 1, 2023

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 securities for March 2023 is 3.77 percent. The
Service determined this rate as the average of the daily determinations of yield
on the 30-year Treasury bond maturing

in February 2053. For plan years beginning in April 2023, the weighted average
of the rates of interest on 30-year Treasury securities and the permissible range
of rates used to calculate current liability are as follows:

For Plan Years Beginning In

Treasury Weighted Average Rates
30-Year Treasury Weighted Average

Permissible Range 90% to 105%

April 2023

2.57

2.32 to 2.70

under § 417(e)(3)(D) are segment rates
computed without regard to a 24-month
average. Notice 2007-81 provides guidelines 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
In general, the applicable interest rates

Month
March 2023

Minimum Present Value Segment Rates
First Segment
Second Segment
5.00
5.20

DRAFTING INFORMATION
The principal author of this notice
is Tom Morgan of the Office of Associ-

May 1, 2023

ate Chief Counsel (Employee Benefits,
Exempt Organizations, and Employment
Taxes). However, other personnel from
the IRS participated in the development

804

Third Segment
5.15

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

Table 2023-3
Monthly Yield Curve for March 2023
Derived from March 2023 Data
Maturity
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
8.5
9.0
9.5
10.0
10.5
11.0
11.5
12.0
12.5
13.0
13.5
14.0
14.5
15.0
15.5
16.0
16.5
17.0
17.5
18.0
18.5
19.0
19.5
20.0

Yield
5.21
5.16
5.10
5.05
4.99
4.95
4.91
4.88
4.87
4.87
4.89
4.91
4.94
4.97
5.01
5.05
5.08
5.12
5.15
5.18
5.21
5.23
5.25
5.27
5.28
5.29
5.30
5.30
5.31
5.31
5.31
5.30
5.30
5.29
5.29
5.28
5.28
5.27
5.26
5.26

Maturity
20.5
21.0
21.5
22.0
22.5
23.0
23.5
24.0
24.5
25.0
25.5
26.0
26.5
27.0
27.5
28.0
28.5
29.0
29.5
30.0
30.5
31.0
31.5
32.0
32.5
33.0
33.5
34.0
34.5
35.0
35.5
36.0
36.5
37.0
37.5
38.0
38.5
39.0
39.5
40.0

Bulletin No. 2023–18

Yield
5.25
5.24
5.24
5.23
5.23
5.22
5.22
5.21
5.21
5.20
5.20
5.19
5.19
5.19
5.18
5.18
5.18
5.17
5.17
5.17
5.17
5.17
5.16
5.16
5.16
5.16
5.16
5.15
5.15
5.15
5.15
5.15
5.14
5.14
5.14
5.14
5.14
5.14
5.14
5.14

Maturity
40.5
41.0
41.5
42.0
42.5
43.0
43.5
44.0
44.5
45.0
45.5
46.0
46.5
47.0
47.5
48.0
48.5
49.0
49.5
50.0
50.5
51.0
51.5
52.0
52.5
53.0
53.5
54.0
54.5
55.0
55.5
56.0
56.5
57.0
57.5
58.0
58.5
59.0
59.5
60.0

Yield
5.13
5.13
5.13
5.13
5.13
5.13
5.13
5.13
5.12
5.12
5.12
5.12
5.12
5.12
5.12
5.12
5.12
5.12
5.12
5.11
5.11
5.11
5.11
5.11
5.11
5.11
5.11
5.11
5.11
5.11
5.11
5.11
5.10
5.10
5.10
5.10
5.10
5.10
5.10
5.10

805

Maturity
60.5
61.0
61.5
62.0
62.5
63.0
63.5
64.0
64.5
65.0
65.5
66.0
66.5
67.0
67.5
68.0
68.5
69.0
69.5
70.0
70.5
71.0
71.5
72.0
72.5
73.0
73.5
74.0
74.5
75.0
75.5
76.0
76.5
77.0
77.5
78.0
78.5
79.0
79.5
80.0

Yield
5.10
5.10
5.10
5.10
5.10
5.10
5.10
5.10
5.10
5.10
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.09
5.08
5.08
5.08
5.08
5.08

Maturity
80.5
81.0
81.5
82.0
82.5
83.0
83.5
84.0
84.5
85.0
85.5
86.0
86.5
87.0
87.5
88.0
88.5
89.0
89.5
90.0
90.5
91.0
91.5
92.0
92.5
93.0
93.5
94.0
94.5
95.0
95.5
96.0
96.5
97.0
97.5
98.0
98.5
99.0
99.5
100.0

Yield
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.08
5.07
5.07
5.07
5.07
5.07
5.07
5.07
5.07
5.07

May 1, 2023

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

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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 taxpayers may use to determine whether certain
expenditures to maintain, repair, replace,
or improve natural gas transmission and
distribution property must be capitalized
as improvements under § 263(a) of the
Internal Revenue Code (Code) or as the
costs of property produced by the taxpayer for use in its trade or business under
§ 263A, or are allowable as deductions
under § 162.1 This revenue procedure
also provides procedures for taxpayers to
obtain automatic consent to change their
method of accounting to the safe harbor
method of accounting permitted by this
revenue procedure.
SECTION 2. BACKGROUND
.01 Taxpayers that transmit and distribute natural gas pay or incur significant
expenditures to maintain, repair, replace,
and improve natural gas transmission
and distribution property. Generally,
whether these expenditures are allowable
as deductions under § 162 for repairs or
maintenance or must be capitalized under
§ 263(a) as improvements to property
depends on whether these expenditures
result in 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 capital1

ized under § 263A depends, generally, on
whether these expenditures are properly
allocable to property produced by the
taxpayer. See § 1.263A-1(a)(3). Applying capitalization principles to natural
gas transmission and distribution property can be particularly difficult, largely
because the property consists of a network
of interconnected assets. As a consequence, there often exists uncertainty as to
whether certain costs to maintain, repair,
replace, and improve parts or components
of such interconnected property are capital expenditures or expenses allowable as
deductions.
.02 To reduce uncertainty and associated disputes between taxpayers and
the IRS regarding whether expenditures
to maintain, repair, replace, or improve
natural gas transmission and distribution
property must be capitalized or are allowable as deductions, this revenue procedure
provides a “natural gas transmission and
distribution property safe harbor method
of accounting” or “NGSH Method” (as
defined under section 4.01 of this revenue procedure) for determining whether
certain costs of maintaining, repairing,
replacing, and improving natural gas
transmission and distribution property are
required to be capitalized under § 263(a)
or § 263A, or may be treated as ordinary
and necessary business expenses for which
a deduction is allowable under § 162(a).
.03 To apply the NGSH Method, a taxpayer must first classify its natural gas

transmission and distribution property
as either linear property (for example,
pipes, fittings, and valves) or non-linear
property (for example, compressors, regulators, and meters). If a taxpayer chooses
to use the NGSH Method for its linear
property, the taxpayer (1) must use the
“safe harbor method for linear property”
(as defined under section 4.02 of this revenue procedure) for all of the taxpayer’s
linear transmission and distribution property and (2) may choose to apply the “safe
harbor method for non-linear property”
(as defined under section 4.03 of this revenue procedure) for all of the taxpayer’s
non-linear transmission and distribution
property. However, if a taxpayer chooses
to use the NGSH Method for its non-linear
property, the taxpayer must use (1) the safe
harbor method for non-linear property for
all of the taxpayer’s non-linear transmission and distribution property and (2) the
safe harbor method for linear property for
all of the taxpayer’s linear transmission
and distribution property.
.04 The safe harbor method for linear property provides different rules for
linear transmission property (generally,
linear property that transmits natural gas
from production facilities to local distribution systems) and for linear distribution
property (generally, linear property that
distributes natural gas to local customers). For linear transmission property, the
safe harbor method for linear property
defines the appropriate units of transmis-

Unless otherwise specified, all “section” or “§” references are to sections of the Code or the Income Tax Regulations (26 CFR part 1).

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May 1, 2023

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 linear distribution property, the safe harbor
method does not define units of property
but divides distribution property into
“distribution mains” and “distribution
service lines” and provides simplified
rules for determining whether the costs
of replacing distribution mains and the
costs of repairing, maintaining, replacing,
or improving distribution service lines
must be capitalized under §§ 263(a) and
263A. See sections 5.03 and 5.07 of this
revenue procedure. A taxpayer using the
safe harbor method for linear property is
required to use it for both its linear transmission property and its linear distribution
property.
.05 The safe harbor method for non-linear property defines units of property and
major components of non-linear transmission and distribution property and provides
that a taxpayer must capitalize the costs of
replacing a unit of non-linear property or
a major component of a unit of non-linear property under §§ 263(a) and 263A.
See section 5.04 of this revenue procedure
and Appendix A of this revenue procedure
(Appendix A). In addition, if a taxpayer
replaces a unit of non-linear property or
a major component of a unit of non-linear
property, the taxpayer must also capitalize
the costs of any repairs, maintenance, or
replacements that directly benefit or are
incurred by reason of the replacement of
the unit of non-linear property or major
component of the unit of non-linear property. Except as otherwise provided in
section 6.04 of this revenue procedure, if
a taxpayer chooses to use the safe harbor
method for non-linear property, the taxpayer must use this safe harbor method
for all its non-linear transmission and distribution property.
.06 This revenue procedure also provides “per se capitalization rules” that
apply to both linear and non-linear property. These per se capitalization rules
identify certain costs that a taxpayer
must treat as capital expenditures if the
taxpayer utilizes the NGSH Method.
See section 5.05 of this revenue procedure. For example, in general, a taxpayer

May 1, 2023

using the NGSH Method is required
to capitalize the costs of additions and
replacements that materially increase
capacity to one or more customers. See
sections 5.05(1)(b) and (2) of this revenue
procedure. Also, under the per se capitalization rules, a taxpayer using the NGSH
Method must capitalize the costs of:
(1) replacing all or part of property if the
taxpayer deducts a loss for the replaced
property (other than a casualty loss) or
takes the adjusted basis of the replaced
property into account in realizing gain or
loss resulting from a sale or exchange of
the replaced property; and (2) repairing
and replacing all or part of property for
which the taxpayer is required to take a
basis adjustment as a result of a casualty loss or relating to a casualty event.
These rules are referred to collectively as
the “disposition/loss per se capitalization
rules.” See section 5.05(1)(g) and (h) of
this revenue procedure.
.07 Replacements of natural gas transmission and distribution property often
involve dispositions of properties that
are replaced. These dispositions generally require taxpayers to recognize gain
or loss, or take a basis adjustment, thus
triggering the disposition/loss per se capitalization rules under the NGSH Method.
Accordingly, the NGSH Method would
not be useful without providing a mechanism to mitigate the effects of these
dispositions and the resulting application
of the disposition/loss per se capitalization rules to a taxpayer utilizing this safe
harbor method. Thus, a taxpayer using
the NGSH Method must include costs
capitalized under the NGSH Method in
general asset accounts as described under
§ 168(i)(4) and § 1.168(i)-1(l). See section 5.08 of this revenue procedure. The
use of general asset accounts limits (1) the
circumstances under which a taxpayer is
required to recognize a loss on the disposition of property, and (2) the circumstances
under which a taxpayer is required to take
a casualty loss or a basis adjustment as a
result of a casualty event. Therefore, the
inclusion of transmission and distribution
property in general asset accounts allows
a taxpayer to avoid triggering the disposition/loss per se capitalization rules. The
use of general asset accounts also allows
a taxpayer to continue to depreciate this
property after its disposition.

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In addition, to facilitate the transition
to the use of general asset accounts, this
revenue procedure requires a taxpayer
using the NGSH Method to make a late
general asset account election under
§§ 168(i)(4) and § 1.168(i)-1(l) for natural
gas transmission and distribution property
that the taxpayer previously placed in service and owns at the beginning of its year
of change. See section 5.08(2) of this revenue procedure. Moreover, to incentivize
taxpayers to use the NGSH method and
to encourage taxpayers to change to the
NGSH method for their first taxable year
ending after May 1, 2023, this revenue
procedure provides a special transition
rule. Under this rule, if a taxpayer changes
to the NGSH Method for its first taxable
year ending after May 1, 2023, the taxpayer does not have to apply certain per
se capitalization rules to amounts paid or
incurred to replace or repair linear property or non-linear property, as applicable,
in taxable years ending on or before May
1, 2023. See section 5.08(3)(a) of this revenue procedure.
.08 The safe harbor method for linear property and the safe harbor method
for non-linear property are methods of
accounting under § 446. Section 446(e)
and § 1.446-1(e) require taxpayers to
secure the consent of the Commissioner
of Internal Revenue (Commissioner)
before changing a method of accounting
for Federal income tax purposes. Section
1.446-1(e)(3)(ii) authorizes the Commissioner to prescribe administrative
procedures setting forth the limitations,
terms, and conditions necessary to permit a taxpayer to obtain consent to
change a method of accounting. Section
6.05 of this revenue procedure provides
the procedures by which a taxpayer may
obtain automatic consent for a change
in method of accounting to use the safe
harbor method for linear property and
the safe harbor method for non-linear
property.
SECTION 3. SCOPE
.01 In general. Only a taxpayer that
meets both of the requirements of section
3.01(1) and (2) of this revenue procedure
may choose to apply the NGSH Method.
(1) The taxpayer has a depreciable
interest in natural gas transmission or dis-

Bulletin No. 2023–18

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 determination of whether a taxpayer satisfies
the requirements of both section 3.01(1)
and (2) of this revenue procedure is made
separately with respect to each member of
a consolidated group and with respect to
each partnership, S corporation, or trust
(other than a grantor trust).
.03 Exclusions. The NGSH Method
does not apply to the following:
(1) The costs of property for the transmission, distribution, control, or storage
of natural gas at a marine liquefied natural
gas terminal capable of shipping or receiving liquid natural gas for import or export;
(2) The costs of enclosures or buildings
suitable for occupation;
(3) The costs of non-linear property that is not specifically identified in
Appendix A (for example, tools, fixtures,
furniture, computer equipment, and other
miscellaneous equipment);
(4) The costs of smart pipeline inspection gauges as defined in section 4.27 of
this revenue procedure; and
(5) The costs of cleaning pipeline
inspection gauges as defined in section
4.28 of this revenue procedure.
SECTION 4. DEFINITIONS
The following definitions apply solely
for purposes of this revenue procedure
(including its appendices):
.01 Natural gas transmission and distribution property safe harbor method of
accounting. “Natural gas transmission and
distribution property safe harbor method
of accounting” or “NGSH Method” means
the safe harbor method for linear property,
the safe harbor method for non-linear
property, and the other applicable rules
set out in this revenue procedure, collectively, regardless of whether the taxpayer
chooses to use both methods, or uses only
the safe harbor method for linear property.
.02 Safe harbor method for linear
property. “Safe harbor method for linear
property” means the method of accounting

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described in sections 5.02, 5.03, and 5.07
of this revenue procedure in conjunction
with the other applicable rules set forth in
this revenue procedure.
.03 Safe harbor method for non-linear property. “Safe harbor method for
non-linear property” means the method
of accounting described in section 5.04
of this revenue procedure in conjunction
with the other applicable rules set forth in
this revenue procedure.
.04 Natural gas transmission property. “Natural gas transmission property”
means real and personal property that
is used to transport, control, and store
natural gas at any point between (1) a
gas processing plant or custody transfer
point and (2) a city gate station or other
delivery point, generally connecting to
a natural gas distribution system. Gas
production wells, gathering lines, and
processing plants are not included in this
definition.
.05 Natural gas distribution property.
“Natural gas distribution property” means
real and personal property that is used to
transport, control, and store natural gas at
any point between (1) a city gate station
or other custody transfer point generally
connecting to a transmission system,
and (2) the customer gas meter or other
delivery point to the customer. For this
purpose, “natural gas distribution property” includes both (1) the city gate station
or other custody transfer point and (2) the
customer gas meter or other delivery point
to the customer.
.06 Linear property. “Linear property” means all natural gas transmission
and distribution property except non-linear property. Examples of linear property
include pipes, valves, tunnels, casing, and
fittings.
.07 Non-linear property. “Non-linear
property” means all natural gas transmission and distribution property that is
compressor station property, gas storage
facility property, measuring and regulating
station property, or meters or regulators,
wherever located. Examples of non-linear
property include compressors, tanks, liquefaction equipment, and structures.
.08 Work order. “Work order” means
a written document that identifies and
defines the scope of a specific project. A
work order may include repairs, maintenance, replacements, and/or improvements

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to natural gas transmission or distribution
property.
.09 Blanket work order. “Blanket
work order” means a written document
that authorizes a project or projects over
a specific period of time, generally not
exceeding one year. A blanket work
order may include repairs, maintenance,
replacements, and/or improvements to
natural gas transmission or distribution
property.
.10 Replacement. “Replacement”
means the installation of property so that
existing property can be removed from
service, whether or not the existing property is physically removed. Generally,
a replacement made pursuant to a work
order is a single replacement for purposes
of this revenue procedure, regardless of
whether (1) the work is performed at the
same or different times, and (2) in the
case of linear property, the property that is
replaced is contiguous or noncontiguous.
Multiple replacements made under separate work orders or made pursuant to a
blanket work order may be aggregated for
purposes of applying the NGSH Method.
See section 5.06 of this revenue procedure
for the rules for aggregating costs related
to linear and non-linear transmission and
distribution property.
.11 City gate station. “City gate station”
means a measuring and regulating station
at which a distribution system receives
natural gas, generally from a transmission
system.
.12 Hydraulic subsystem. “Hydraulic
subsystem” means all linear transmission
property used to direct the flow of natural gas that is maintained within the same
operating pressure range in the shortest
section between any two of the following
points:
(1) a gas processing plant;
(2) a compressor station at a storage
facility;
(3) a compressor station not described
in section 4.12(2) of this revenue procedure (including between two compressor
stations described in this section 4.12(3));
(4) a regulator (including between two
regulators);
(5) the point where the taxpayer’s distribution system begins; or
(6) a custody transfer point where the
gas is delivered to or from another party.
For example, a regulator located between

May 1, 2023

another regulator and a compressor station
divides that section of linear transmission property into two separate hydraulic
subsystems, even if both subsystems are
maintained within the same operating
pressure range.
.13 Compressor station property.
“Compressor station property” means
property that supplies the energy to move
natural gas at increased pressure at storage facilities or in transmission lines,
including but not limited to compressors,
instrumentation and controls, meters,
regulators, measuring equipment, odorizing equipment, gas detection equipment,
electric supply equipment, equipment to
maintain pipeline quality gas, mounting
pads, buildings, and fencing or walls.
.14 Gas storage facility property. “Gas
storage facility property” means property
at an above ground or underground gas
storage facility, including a compressed or
liquefied natural gas storage facility, and
an underground storage facility in a salt
formation or a depleted well or well field.
Gas storage facility property does not
include property at a liquefied natural gas
marine terminal capable of shipping or
receiving liquefied natural gas for import
or export.
.15 Measuring and regulating station property. “Measuring and regulating
station property” means property at a
location that measures or regulates natural
gas, including but not limited to meters,
regulators, and gauges.
.16 Measuring equipment. “Measuring equipment” means equipment used to
measure the pressure or temperature of the
gas. As used in this revenue procedure, the
term does not include a meter that measures gas flow, as defined in section 4.23
of this revenue procedure.
.17 Instrumentation and controls.
“Instrumentation and controls” means the
analog and digital devices that measure,
monitor, or control the equipment at storage
facilities, compressor stations, and measuring and regulating stations (including city
gate stations). Instrumentation and controls
include SCADA (supervisory control and
data acquisition) equipment and measuring
and regulating equipment. As used in this
revenue procedure, however, instrumentation and controls do not include assets that
are treated as separate units of property (for
example, meters or regulators).

May 1, 2023

.18 Distribution main. “Distribution
main” means a distribution line that serves
as a common source of supply for more
than one distribution service line. “Distribution mains” means more than one
section of distribution main in a natural
gas distribution system.
.19 Distribution service line. “Distribution service line” means a line that carries
natural gas from the distribution main to
the customer gas meter.
.20 Distribution service line costs.
“Distribution service line costs” means
direct and indirect costs paid or incurred
to repair, maintain, replace, or improve
distribution service lines.
.21 Lateral line. “Lateral line” means a
line in a natural gas distribution or transmission system that branches away from
the central and primary part of the system.
.22 Compressor. “Compressor” means
a mechanical device for increasing the
pressure of gas.
.23 Meter. “Meter” means an instrument for measuring and indicating or
recording the flow of gas that has passed
through it.
.24 Regulator. “Regulator” means a
device that reduces the pressure in a gas
line and maintains the pressure within a
constant band.
.25 Well. “Well” means a cased bore
hole used for gas input or output for an
underground storage reservoir, including
a storage well.
.26 Equipment to maintain pipeline
quality gas. “Equipment to maintain
pipeline quality gas,” also known as
“purification equipment,” means equipment used to ensure that the gas moving
through a line is maintained within certain
parameter. This term includes, but is not
limited to, the equipment used to remove
liquids and impurities from the gas, and
the equipment used to heat or cool the gas
to make it suitable for movement through
the line.
.27 Smart pipeline inspection gauges.
“Smart pipeline inspection gauges,” also
known as “smart pigs,” are devices that
are equipped with sensors that gauge
the thickness of pipes they are traveling
through and detect cracks, fissures, erosion and other problems that may affect
the integrity of the pipeline. Smart pipeline
inspection gauges are not included within
the definition of natural gas transmission

810

or distribution property for purposes of
this revenue procedure.
.28 Cleaning pipeline inspection
gauges. “Cleaning pipeline inspection
gauges,” also known as “cleaning pigs,”
are devices that have brushes, scrapers,
or similar tools and are used for cleaning pipelines by removing sedimentation
and build-up that can impede the flow of
gas. Cleaning pipeline inspection gauges
are not included within the definition of
natural gas transmission or distribution
property for purposes of this revenue
procedure.
.29 Odorizing equipment. “Odorizing
equipment” means equipment that injects
an odorant or other additive into the gas
so that leaks can be detected by the sense
of smell.
.30 Gas detection equipment. “Gas
detection equipment” means equipment
that indicates the existence of natural gas
in a specific area.
.31 Electric supply equipment. “Electric supply equipment” means equipment
that supplies electricity to equipment at a
compressor station or gas storage facility,
including but not limited to generators,
batteries and chargers, and transformers.
.32 Liquefaction equipment. “Liquefaction equipment” means equipment that
is used in connection with the liquefaction
of natural gas, including but not limited to
cold boxes, heat exchangers, condensers,
and vaporizing units.
.33 Cathodic protection. “Cathodic
protection” means a technique to prevent
the corrosion of a metal surface by making
that surface the cathode of an electrochemical cell.
SECTION 5. NATURAL
GAS TRANSMISSION AND
DISTRIBUTION PROPERTY
SAFE HARBOR METHOD OF
ACCOUNTING
.01 In general.
(1) A taxpayer using the NGSH Method
must apply the safe harbor method for linear property provided in sections 5.02 and
5.03 of this revenue procedure to the direct
and indirect costs of replacing all its linear
transmission and distribution main property, including any unit of property rules
described therein. A taxpayer using the
NGSH Method must also apply the safe

Bulletin No. 2023–18

harbor method for distribution service line
costs as provided in section 5.07 of this
revenue procedure. Moreover, a taxpayer
using the NGSH Method may, but is not
required to, apply the safe harbor method
for non-linear property provided in section 5.04 of this revenue procedure to the
direct and indirect costs of repairing, maintaining, replacing, and improving all its
non-linear transmission and distribution
property, including the application of the
units of property and major components
described in Appendix A. In addition,
except as provided in section 5.08(3)
(a) of this revenue procedure, a taxpayer
using the NGSH Method must apply the
per se capitalization rules provided in section 5.05 of this revenue procedure and
the aggregation rules provided in section
5.06 of this revenue procedure to property subject to the NGSH Method. Finally,
a taxpayer using the NGSH Method
must include certain costs of natural gas
transmission and distribution property in
general asset accounts as provided in section 5.08 of this revenue procedure.
(2) Solely for purposes of this revenue
procedure, the IRS will respect a reasonable and consistently applied designation
of property by the taxpayer as either
transmission or distribution property for
Federal or State regulatory purposes,
whichever is applicable. If the taxpayer is
unregulated, the IRS will respect a reasonable and consistently applied designation
that the taxpayer uses for its books and
records.
(3) A taxpayer may not rely on the unit
of property definitions provided in this
revenue procedure for any other purpose
of the Code or regulations, including for
determining the unit of property under
other sections of the Code or determining the asset for depreciation purposes
(including placed in service, retirements,
dispositions, or classification under
§ 168(e) or Rev. Proc. 87-56, 1987-2 C.B.
674) for the same or similar type of assets.
(4) Amounts required to be capitalized under the NGSH Method are
capital expenditures and must be taken
into account through a charge to capital
account or basis. Amounts that are paid or
incurred for MACRS property and that are
capitalized under this NGSH Method are
accounted for in the manner described in
section 5.08 of this revenue procedure.

Bulletin No. 2023–18

.02 Safe harbor method for linear
property—application to transmission
property.
(1) Unit of property for linear transmission property. For purposes of this
revenue procedure, the unit of property
for linear natural gas transmission property is the linear property within each
hydraulic subsystem as defined in section 4.12 of this revenue procedure. If a
transmission segment is composed of two
or more parallel lines, each line between
each compressor station or other connection point is a separate unit of property. A
lateral line on a transmission line is not a
separate unit of property unless there is a
compressor station or regulator at the junction point between the lateral line and the
main transmission line. If a lateral line can
be treated as part of a unit of property with
more than one main transmission line, the
taxpayer should designate the main line
with which the lateral line is associated
and follow that designation consistently.
(2) Simplified rule for replacements of
linear transmission property. Whether a
taxpayer using the safe harbor method for
linear property must capitalize the cost of
a replacement of linear transmission property is determined by the length of the
line replaced. If more than 10 percent of
the length of the unit of linear transmission property is replaced, the cost of the
replacement must be capitalized under
§§ 263(a) and 263A. If 10 percent or less
of the length of the unit of linear transmission property is replaced, the cost of the
replacement is not required to be capitalized under § 263(a) or § 263A. The cost
of the replacement includes the direct and
indirect costs of replacing the pipe and
any associated linear property, including,
but not limited to, connectors, cathodic
protection, valves, casing, tunnels, instrumentation and controls, and structural
supports for such property.
(3) Blanket work orders.
(a) Allocation. To the extent a taxpayer cannot specifically identify whether
amounts charged to a blanket work order
are for a replacement of linear transmission property greater than 10 percent of
the unit of linear transmission property, the
taxpayer may use any reasonable method
to allocate costs charged to the blanket
work order if the reasonable method is
consistently applied by the taxpayer.

811

(b) De minimis charges. A taxpayer
that adheres to a policy that limits perevent charges under a blanket work
order to replacements of property costing $50,000 or less is not required to
capitalize the costs of replacing linear
transmission property charged to the blanket work order. Replacements of property
qualifying under this de minimis rule
are not taken into account in determining whether more than 10 percent of the
length of the unit of linear transmission
property is replaced under section 5.02(2)
of this revenue procedure or in applying
the aggregation requirement in section
5.06 of this revenue procedure.
.03 Safe harbor method for linear property—application to distribution property.
(1) In general. For purposes of determining whether the costs of replacing
linear distribution property must be capitalized under the NGSH Method, the
unit of linear distribution property is not
defined. Instead, the taxpayer must initially determine whether the costs are for
the replacement of distribution mains as
defined in section 4.18 of this revenue
procedure or are distribution service line
costs as defined in section 4.20 of this revenue procedure. To determine whether the
costs of replacing distribution mains must
be capitalized, the taxpayer must apply the
simplified rule provided in section 5.03(2)
of this revenue procedure. To determine
whether distribution service line costs
must be capitalized, the taxpayer must
apply the simplified rules provided in section 5.07 of this revenue procedure.
(2) Simplified rule for replacements of
distribution mains. Whether a taxpayer
using the safe harbor method for linear property must capitalize the cost of
replacing distribution mains is determined
by the length of the distribution mains
replaced. If more than four miles of distribution mains are replaced, the cost of
the replacement must be capitalized under
§§ 263(a) and 263A. If four miles or less
of distribution mains are replaced, the
cost of the replacement is not required to
be capitalized under § 263(a) or § 263A.
The cost of the replacement includes the
direct and indirect costs of replacing the
distribution mains and any associated linear property, including, but not limited to,
connectors, cathodic protection, valves,
casing, tunnels, instrumentation and con-

May 1, 2023

trols, and structural supports for such
linear property.
(3) Blanket work orders.
(a) Allocation. To the extent a taxpayer cannot specifically identify whether
amounts charged to a blanket work order
are for the replacement of distribution
mains greater than four miles, the taxpayer may use any reasonable method to
allocate costs charged to the blanket work
order if the reasonable method is consistently applied by the taxpayer.
(b) De minimis charges. A taxpayer
that adheres to a policy that limits perevent charges under a blanket work
order to replacements of property costing
$50,000 or less is not required to capitalize
the costs of distribution mains replacements charged to the blanket work order.
Replacements of property qualifying
under the de minimis rule in this section
5.03(3)(b) are not taken into account in
determining replacement length under
section 5.03(2) of this revenue procedure
or in applying the aggregation requirement
in section 5.06 of this revenue procedure.
.04 Safe harbor method for non-linear
property – application to transmission
and distribution property.
(1) Applicability. A taxpayer may use
the safe harbor method for non-linear
property only if the taxpayer uses the safe
harbor method for linear property. However, a taxpayer is not required to apply
the safe harbor method for non-linear
property if it uses the safe harbor method
for linear property. If a taxpayer does not
use the safe harbor method for non-linear
property, then the taxpayer must apply
§§ 162, 263(a), 263A, and the regulations
thereunder to determine the appropriate
units of property for its non-linear property and to determine whether amounts
paid or incurred to repair, maintain,
replace, or improve these units of property
must be capitalized.
(2) Units of property under the safe
harbor method for non-linear property.
For purposes of applying the safe harbor
method for non-linear property, the units
of property and corresponding major
components of non-linear property are
identified in Appendix A. A taxpayer that
uses a unit of property definition provided
in Appendix A must also use the major
component definitions provided in Appendix A for that unit of property. Similarly,

May 1, 2023

a taxpayer that uses a major component
definition provided in Appendix A must
also use the unit of property definition
provided in Appendix A associated with
that major component.
(3) Simplified rule for replacements
of non-linear property. The safe harbor
method for non-linear property applies to
the direct and indirect costs paid or incurred
to repair, maintain, replace, or improve
the taxpayer’s non-linear transmission
and distribution property. If the taxpayer
replaces a unit of non-linear property or
a major component of a unit of non-linear
property as identified in Appendix A, then
the taxpayer must capitalize the amounts
paid to replace the unit of non-linear property or major component of the unit of
non-linear property under §§ 263(a) and
263A. In addition, if a taxpayer replaces a
unit of non-linear property or a major component of a unit of non-linear property, the
taxpayer must also capitalize the costs of
any repairs, maintenance, or replacements
that directly benefit or are incurred by
reason of the replacement of the unit of
non-linear property or major component
of the unit of non-linear property. If the
taxpayer pays or incurs amounts to repair,
maintain, replace, or improve non-linear
transmission or distribution property, but
does not replace either a unit of non-linear
property or a major component of a unit of
non-linear property as part of these activities, then the taxpayer is not required to
capitalize the amounts paid or incurred for
such activities under § 263(a) or § 263A.
However, if a taxpayer pays or incurs
amounts to repair, maintain, replace, or
improve its non-linear transmission or distribution property, and these costs relate
to per se capital expenditures described
under section 5.05 of this revenue procedure, then the amounts paid or incurred
must be capitalized under section 5.05 of
this revenue procedure.
.05 Per se capital expenditures.
(1) In general. Except as provided in
section 5.08(3)(a) of this revenue procedure, a taxpayer using the NGSH Method
must capitalize the direct and indirect
costs described in section 5.05(1)(a)
through (j) of this revenue procedure to
the extent these costs are paid or incurred
with respect to linear property or non-linear property subject to the NGSH Method,
notwithstanding any other provision of

812

this revenue procedure. Per se capital
expenditures include:
(a) The costs of property necessary to
add one or more new customers;
(b) The costs of materially increasing
capacity of the property to one or more
existing or potential customers (see section 5.05(2) of this revenue procedure
for the application of this rule to linear
property);
(c) The costs of adding a unit of non-linear property or adding a major component
of a unit of non-linear property other than
as a replacement, as defined in section
4.10 of this revenue procedure, for an
existing major component;
(d) The costs of property that extends
a transmission or distribution system (see
section 5.05(3) of this revenue procedure
for the application of this rule to the costs
of additional linear property required to
relocate or replace an existing line);
(e) The costs of property that adds
cathodic protection, protective wrapping,
or protective coating to linear property;
(f) The costs of adding instrumentation
and control equipment, including remote
actuation or monitoring equipment, to
property that did not previously have similar equipment; for these purposes, new
instrumentation and control equipment
is not similar if it provides additional
functionality;
(g) The costs of replacing all or part of
property if the taxpayer deducts a loss for
the replaced property (other than a casualty loss), or takes the adjusted basis of
the replaced property into account in realizing gain or loss resulting from a sale or
exchange of the replaced property;
(h) The costs of repairing or replacing
all or part of property as a result of damage for which the taxpayer is required to
take a basis adjustment as a result of a
casualty loss under § 165, or relating to a
casualty event described in § 165;
(i) The costs of easements or other
rights in real property; and
(j) The costs of adapting property to a
new or different use.
(2) Materially increasing capacity of
linear property.
(a) Determining materiality. For purposes of applying section 5.05(1)(b) of
this revenue procedure to linear transmission property or linear distribution
property, an expenditure for linear prop-

Bulletin No. 2023–18

erty materially increases capacity to one
or more existing or potential customers
if the work performed increases capacity by more than five percent to one or
more existing or potential customers.
In the case of transmission property, an
increase in capacity is determined based
on the increase in the capacity of the
hydraulic subsystem, measured in terms
of millions of cubic feet per day. In the
case of distribution property, an increase
in capacity is determined based on the
increase in the throughput of gas to one
or more existing or potential customers
served or to be served by the added or
replaced property, measured in terms
of thousands of cubic feet per hour. For
purposes of section 5.05(1)(b) of this revenue procedure, an increase in capacity
does not include amounts paid to return
linear property to its original capacity
prior to any wear, tear, or other damage
necessitating such expenditure.
(b) Taxpayer’s purpose. A taxpayer is
not required to capitalize costs that materially increase capacity to linear property
under section 5.05(2)(a) of this revenue
procedure if the taxpayer can establish
with reasonable certainty, through its
books and records, that the principal purpose of an addition or replacement of
linear property was for safety reasons, to
standardize its system, or to comply with
regulatory requirements, unrelated to
increasing capacity. However, these costs
may be subject to capitalization under
sections 5.02, 5.03, or 5.07 of this revenue
procedure or other per se capitalization
rules under this section 5.05.
(3) Property that extends a system.
For purposes of applying section 5.05(1)
(d) of this revenue procedure, the cost of
property that extends a transmission or
distribution system does not include the
cost of additional linear property required
to relocate or replace an existing line that
will continue to run between the same
two endpoints. However, if more than 10
percent of the length of the original unit
of property is replaced, in the case of a
replacement of linear transmission property, the costs of the replacement must
be capitalized under section 5.02(2) of
this revenue procedure. If more than four
miles of distribution mains is replaced, in
the case of a replacement of distribution
mains, the cost of the replacement must be

Bulletin No. 2023–18

capitalized under section 5.03(2) of this
revenue procedure.
(4) Special rule for identified distribution service line costs associated with
distribution mains. If the taxpayer can
identify with reasonable accuracy distribution service line costs associated with
distribution main costs that are treated
as per se capital expenditures under this
section 5.05, then the identified distribution service line costs are also treated
as per se capital expenditures under this
section 5.05. For rules regarding identified and unidentified distribution service
line costs, see section 5.07 of this revenue procedure.
(5) Coordination with other rules.
Replacements of property for which
the replacement costs are per se capital expenditures under this section 5.05
are not taken into account in determining whether more than 10 percent of the
length of the unit of linear transmission
property is replaced for purposes of applying section 5.02 of this revenue procedure,
or in determining whether more than four
miles of distribution mains are replaced
for purposes of section 5.03 of this revenue procedure.
(6) Examples. The following examples
illustrate the application of this section
5.05. In each example, it is assumed that
(a) the taxpayer is a corporation and files
its Federal income tax return on an accrual
method and a calendar year basis, (b) the
taxpayer uses the safe harbor method for
linear property and the safe harbor method
for non-linear property for all its natural
gas transmission and distribution property, and (c) the taxpayer does not make
an election under § 1.168(i)-1(e)(3)(ii)
(disposition of all assets remaining in a
general asset account) or § 1.168(i)-1(e)(3)
(iii) (disposition of an asset in a qualifying
disposition). In addition, for the following
examples, it is assumed that none of the
aggregation requirements of section 5.06
of this revenue procedure apply.
(a) Example 1. (i) Z is a local natural gas distribution company that supplies gas to an industrial
customer via a three-inch diameter distribution service line. Due to planned expansion of its facility, the
customer will require more gas than can be supplied
via the existing line. Z’s records include correspondence with the customer indicating that Z agreed to
install a second three-inch distribution service line
and a second meter to meet the customer’s need for
additional gas at its facility. As a result of Z’s installation of a second three-inch distribution service line,

813

throughput of gas to the customer is increased by 100
percent.
(ii) The cost of installing the second distribution
service line is a per se capital expenditure under section 5.05(1)(b) of this revenue procedure because it
increases Z’s capacity to its customer by more than
five percent and Z’s records reflect that the distribution service line is added for the principal purpose
of increasing capacity to Z’s customer. The cost of
installing a second meter must be capitalized under
the per se capitalization rule in section 5.05(1)(c) of
this revenue procedure because the new meter is an
addition of a unit of non-linear property defined in
section 2.04 of Appendix A.
(b) Example 2. Y is a natural gas transmission
company that owns and operates a natural gas transmission pipeline that is 300 miles in length. Section
A of this pipeline runs for 80 miles between two
compressor stations, and is a hydraulic subsystem
that is a unit of property. The pipe in Section A is 12
inches in diameter, except for a seven-mile segment
that is 10 inches in diameter. Y incurs costs to replace
the seven-mile 10-inch segment with 12-inch pipe
in order to increase the capacity of Section A. As a
result of the replacement, the capacity of Section A
to Y’s customers, as measured in terms of millions
of cubic feet of gas per day, increased by more than
five percent. In addition, Y’s records do not specifically indicate a principal purpose for replacing the
seven-mile segment. Accordingly, the cost of replacing the existing 10-inch transmission line with the
larger 12-inch transmission line must be capitalized
as a per se capital expenditure under section 5.05(1)
(b) of this revenue procedure.
(c) Example 3. X is a natural gas transmission
company that owns and operates a natural gas transmission pipeline that is 300 miles in length. Section
B of this transmission pipeline runs for 80 miles
between two compressor stations and is a hydraulic subsystem that is a unit of property. The pipe in
Section B is 10 inches in diameter. X replaces seven
miles of Section B with 12-inch pipe. As a result
of the replacement, the capacity of Section B to
X’s customers, as measured in terms of millions of
cubic feet of gas per day, increased by two percent.
Because the replacement did not result in an increase
in Section B’s capacity by more than five percent,
the cost of replacing the seven miles of pipe is not
a per se capital expenditure under section 5.05(1)
(b) of this revenue procedure and, because less than
10 percent of Section B (7 miles out of 80 miles =
8.8 percent) is replaced, the cost is not required to
be capitalized under section 5.02(2) of this revenue
procedure.
(d) Example 4. (i) W is a local natural gas distribution company that supplies gas to a group of
existing customers via an older three-inch diameter
distribution main and individual distribution service
lines. Pursuant to regulatory requirements, W performs regular safety risk assessments that take into
account the age and composition of the pipeline at
various locations. Based on this safety assessment,
W determines it is necessary to replace three miles of
distribution mains. The distribution main is replaced
with four-inch diameter pipe, which is one of the
standard sizes currently used by W for all distribution
main replacements. W’s books and records indicate
that the principal purpose of the replacement was the

May 1, 2023

result of the safety risk assessment. W can identify
with reasonable accuracy the distribution service line
costs that are associated with the distribution mains
replacement.
(ii) Pursuant to section 5.05(2)(b) of this revenue
procedure, the cost to replace the distribution main is
not a per se capital expenditure under section 5.05(1)
(b) of this revenue procedure because the taxpayer’s
books and records indicate that the principal purpose
of the distribution main replacement was to reduce
safety risk. Additionally, because the length of the
distribution main replacement is less than four miles,
the cost of the distribution main replacement is not
required to be capitalized under section 5.03(2) of
this revenue procedure. Similarly, because W can
identify the costs of replacing the distribution service lines with the distribution main replacement, the
cost of replacing the associated distribution service
lines is not a per se capital expenditure under section 5.05(1)(b) of this revenue procedure and is not
required to be capitalized under section 5.07(2)(b)(ii)
of this revenue procedure.
(e) Example 5. (i) V is a local natural gas distribution company that supplies natural gas to a group of
existing customers at the edge of its service area via
three miles of three-inch diameter distribution main,
and individual distribution service lines. V’s records
reflect that certain customers were experiencing gas
delivery issues. Consequently, V replaces the entire
three-mile segment with four-inch diameter pipe,
as well as the associated service lines. V’s books
and records do not indicate any principal purpose
of replacing the three-mile segment of distribution
main other than to address its customer’s gas delivery issues. V’s replacement of the three-mile segment
of distribution main increased the throughput of gas
to its existing customers by seven percent.
(ii) Because the replacement of the distribution
main results in an increase in the throughput of gas
to the customers served by the distribution main
of more than five percent, the cost to replace the
three miles of distribution mains is a per se capital
expenditure under section 5.05(1)(b) of this revenue procedure. Additionally, because the cost of
the distribution main replacement is a per se capital
expenditure, the cost of replacing the associated distribution service lines is a per se capital expenditure
under sections 5.05(4) and 5.07(2)(a) of this revenue
procedure.
(f) Example 6. (i) U is a local natural gas distribution company that owns and operates 160 miles of
distribution mains. U’s distribution mains currently
include one-, two-, three-, and four-inch diameter
pipe. The diameters and materials vary depending on
the year of installation. U is currently standardizing
its distribution mains by using pipe in two-inch and
four-inch diameters. Any distribution main pipe that
is replaced is replaced with one of these two standard
sizes. U replaces 875 feet of three-inch diameter pipe
with four-inch diameter pipe, which had the effect of
increasing its throughput to one or more existing or
potential customers by more than five percent. U’s
books and records indicate that its use of the larger
diameter pipe was necessary to standardize its system with currently available sizes of pipe.
(ii) Because U’s books and records indicate that
the replacement is made to standardize its system,
pursuant to section 5.05(2)(b) of this revenue pro-

May 1, 2023

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 capitalized under section 5.03(2) of this revenue procedure.
(g) Example 7. (i) T is a local natural gas distribution company that owns and operates 160 miles
of natural gas distribution mains. T’s distribution
mains include iron pipe and polyethylene pipe. T is
currently using polyethylene pipe when it needs to
replace pipe in its distribution mains because it considers polyethylene pipe to be better pipe for several
reasons. T replaces three miles of four-inch diameter iron pipe in its distribution mains with four-inch
diameter polyethylene pipe. There is no change in
the throughput of gas to customers served by the distribution main as a result of this replacement.
(ii) The cost of the replacement is not a per se
capital expenditure under section 5.05(1)(b) of this
revenue procedure because the replacement does not
materially increase capacity to one or more existing
or potential customers. Additionally, because the
distribution main replacement is for four miles or
less, the cost of the replacement is not required to
be capitalized under section 5.03(2) of this revenue
procedure.
(h) Example 8. S, a local natural gas distribution
company, is required to relocate a distribution main
to accommodate construction of a road. In order to
reroute its distribution main around the construction
site, S replaces one mile of pipe and also adds 1,000
feet of pipe to the distribution system. Notwithstanding the addition of pipe to the distribution system,
the cost of the relocation is not a per se capital
expenditure under section 5.05(1)(d) of this revenue procedure because the pipeline continues to run
between the same two endpoints. Additionally, the
cost of the relocation is not required to be capitalized under section 5.03(2) of this revenue procedure
because the replacement of distribution main pipe is
four miles or less.

.06 Aggregation requirements.
(1) General rule. For purposes of determining whether the applicable thresholds
for capitalization of property provided in
sections 5.02, 5.03, and 5.04 of this revenue procedure are met, a taxpayer must
aggregate multiple replacements if all of
the following requirements are met:
(a) The replacements are within –
(i) the same unit of property, for
non-linear property and linear transmission property, or
(ii) the same five-digit United States
Postal Service ZIP Code delivery area, for
linear distribution property;
(b) The replacements are described in
one authorizing document, as defined in
section 5.06(2) of this revenue procedure;
and
(c) The authorizing document –
(i) identifies the property with respect
to which the replacements will occur

814

or the locations where property will be
replaced;
(ii) identifies the amount of pipe to be
replaced, or total cost of the replacements;
and
(iii) provides that the replacements are
expected to be completed within five years
after the date of the authorizing document.
If the authorizing document does not
provide a time period over which replacements will be completed, this requirement
will be considered to be met unless it is
determined upon original authorization
that it will take more than five years to
complete the replacements.
(2) Authorizing document.
(a) For purposes of this section 5.05 of
this revenue procedure, the term “authorizing document” means the following:
(i) a regulatory commission decision
that requires replacements as part of an
identified program aimed at a specific
purpose;
(ii) a written project authorization
aimed at a specific purpose;
(iii) a work order as defined under section 4.08 of this revenue procedure; or
(iv) a blanket work order as defined
under section 4.09 of this revenue procedure and which is aimed at a specific
purpose.
(b) A regulatory commission decision
does not include a decision, whether or
not designated as an “order,” that authorizes expenditures for replacements but
does not require replacements to be made.
(3) General and specific authorizing
documents. If replacements are described
by a general authorizing document as
well as one or more specific authorizing
documents (for example, a regulatory
commission decision and a written project
authorization implementing the regulatory commission decision), aggregation is
based on the most general authorizing document that meets the requirements
of section 5.06(1)(c) of this revenue procedure. For example, if a general authorizing
document provides that replacements are
not expected to be completed within five
years of this authorizing document, then
aggregation of the replacements pursuant to this authorizing document is not
required. However, if a subsequent more
specific authorizing document implementing that same program or project provides
that certain replacements are expected

Bulletin No. 2023–18

to be completed within five years of this
subsequent authorizing document, then
aggregation of the replacements described
in the subsequent authorizing document is
required, provided that the other requirements described in section 5.06(1) of this
revenue procedure are met.
(4) Aggregation of replacements across
multiple years. Multiple replacements that
meet the requirements described in section 5.06(1) of this revenue procedure
are aggregated without regard to whether
they are performed in one year or multiple
years.
(5) Modifications. Modifications to an
authorizing document, or to the work done
pursuant to an authorizing document, that
occur within the taxable year are taken
into account in determining whether to
aggregate replacements, and whether to
capitalize the expenditures, in that taxable
year, but do not affect the aggregation of
replacements pursuant to that authorizing
document in a prior taxable year.
(6) Anti-abuse rule. If a taxpayer acts
(a) to divide closely related transmission or distribution property replacement
projects into multiple written project
authorizations, work orders, or blanket
work orders or (b) to mischaracterize the
intended or expected scope of a project, in
order to avoid the application of the aggregation rules under this section 5.06, rather
than for non-tax business reasons, appropriate adjustments will be made by the
Commissioner to carry out the purposes
of this revenue procedure.
(7) Examples. The following examples
illustrate the application of this section
5.06. In each example, it is assumed that
(a) the taxpayer is a corporation and files
its Federal income tax return on an accrual
method and a calendar year basis, (b) the
taxpayer uses the safe harbor method for
linear property and the safe harbor method
for non-linear property for all its natural
gas transmission and distribution property, and (c) the taxpayer does not make
an election under § 1.168(i)-1(e)(3)(ii)
(disposition of all assets remaining in a
general asset account) or § 1.168(i)-1(e)
(3)(iii) (disposition of an asset in a qualifying disposition).
(a) Example 1. (i) R is a natural gas distribution
company in State A. The Public Utility Commission
(Regulator) of State A sets the rates and approves
tariffs for R. Regulator issues Rate Order 12345 as a
result of certain rate proceedings. Rate Order 12345

Bulletin No. 2023–18

allows for the incremental recovery of up to an
additional $30 million annually in revenue through
rates and tariffs. Rate Order 12345 states that these
dollars are for the recovery of incremental operating
expense, maintenance expense, and return on investment related to the replacement of distribution mains
in its natural gas distribution system; however, no
specific replacements are required, and Rate Order
12345 does not provide a time period over which
replacements will be completed. R makes annual
filings documenting such costs, which match revenue billed to incremental expense and include R’s
allowed return on investment. The specific distribution main replacements are determined by R based
on known conditions and risk analysis.
(ii) For purposes of determining whether the
replacement costs are capitalized under section 5.03
of this revenue procedure, aggregation of pipeline
replacements is not required under this section 5.06
because Rate Order 12345 (A) does not identify a
program aimed at a specific purpose for the replacements; (B) does not require specific replacements
to be made; (C) does not identify the property with
respect to which the replacements will occur or the
locations for the replacements; (D) does not identify
the amount of pipe or the total cost of the replacements; and (E) does not specify that the replacements
are within the same Zip Code. All these criteria must
be satisfied for the aggregation requirement of this
section 5.06 to apply to replacements performed
under Rate Order 12345.
(b) Example 2. Q is a local natural gas distribution company. Based on estimated general
maintenance and upgrade costs and anticipated revenues through its rates and tariffs, Q budgets $100
million during Year 1 for replacements within its
distribution system. For purposes of determining
whether the distribution main replacement costs are
capitalized under section 5.03 of this revenue procedure, an aggregation of pipeline replacements is not
required under this section 5.06 because Q’s budget document is not a written project authorization
aimed at a specific purpose.
(c) Example 3. P is a local natural gas distribution
company. P issues a blanket work order for replacements of less than 2,000 feet of distribution mains.
The blanket work order is used predominantly for the
repair of leaks, but does not establish a project aimed
at a specific purpose. P performs several replacements under the blanket work order to repair leaks.
For purposes of determining whether the replacement costs are capitalized under section 5.03 of this
revenue procedure, an aggregation of distribution
main replacements under the blanket work order is
not required under this section 5.06 because the blanket work order is not an authorizing document under
section 5.06(2) of this revenue procedure.
(d) Example 4. (i) O is a natural gas distribution
company in State B. Following an explosion near a
population center in State B that may be attributable
to Type L pipe deteriorating faster than anticipated,
Regulator issues an order in Year 1 requiring all
Type L pipe used in the transmission or distribution of natural gas or other combustible material in
State B to be replaced within five years to eliminate
a safety risk to State B citizens. The order also specifies procedures for applying for a special tariff to
support replacements of Type L pipe. In response to

815

this order, O’s management instructs its engineering
department to initiate a project to identify all Type
L pipe in its distribution system in State B. O issues
a written project authorization that will involve
a review of its purchases of Type L pipe, physical
identification of the pipe, and inspection of sections
of pipeline. As the locations of Type L pipe are identified, O prepares work orders to replace the Type L
pipe. In one ZIP Code delivery area, O identifies six
sections of Type L distribution mains, totaling eight
miles, and each of these sections are replaced under
six separate work orders, as they are identified. Each
work order identifies the location and the amount
of the distribution mains to be replaced. Each work
order is for a replacement of less than four miles of
distribution mains.
(ii) For purposes of determining whether the
replacement costs are capitalized under section
5.03 of this revenue procedure, the replacements
are not aggregated under this section 5.06 under the
Regulator’s order because, although the order is an
authorizing document within the meaning of section
5.06(2) of this revenue procedure, the order does not
identify the amount or costs of the distribution mains
to be replaced, as required by section 5.06(1)(c)(ii)
of this revenue procedure. Similarly, the replacements are not aggregated under the written project
authorization issued by O because the authorization
does not identify the amount or the costs of the distribution mains to be replaced. See section 5.06(1)
(c)(ii) of this revenue procedure. Rather, each of
the six work orders qualify as separate authorizing
documents under section 5.06(2) of this revenue
procedure and provides the information required in
section 5.06(1)(c). Because neither the Regulator’s
order nor the written project authorization meets the
requirements for aggregation under this section 5.06,
and each work order constitutes a separate authorizing document for the replacement of less than four
miles of distribution mains, the costs of the replacements are not required to be capitalized under section
5.03 of this revenue procedure.
(e) Example 5. (i) The facts are the same as in
Example 4, except that in response to the Regulator’s
order, in Year 1, O’s management issues a written
project authorization for the replacement of all Type
L pipe in County Z in State B, identifying the quantity and location of all Type L pipe in County Z, and
authorizing $2 million for this purpose. County Z
falls within two ZIP Code delivery areas, Area F and
Area G. The project authorization does not provide a
time period in which the replacements will be completed but there is no reason to expect that the project
will take longer than five years.
(ii) For purposes of determining whether the
replacement costs are capitalized under section 5.03
of this revenue procedure, the replacements are
aggregated under this section 5.06 pursuant to O’s
written project authorization, which authorizes the
replacement of distribution mains for a specific purpose and identifies the location of the replacements
and the amount of distribution mains to be replaced.
Accordingly, for each of the ZIP Code delivery
areas affected by the written project authorization,
replacements within that ZIP Code delivery area
that are covered by the written project authorization
are aggregated, even though the replacements may
be noncontiguous, may occur over more than a sin-

May 1, 2023

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 revenue procedure, the replacement costs of distribution
mains in Area F are capitalized and the replacement
costs of distribution mains in Area G are not required
to be capitalized.
(f) Example 6. (i) The facts are the same as in
Example 4 except O knows that it also has Type L
pipe in its distribution systems in State Y. In response
to Regulator’s order, O issues a written project authorization authorizing its crews in State Y to replace all
Type L pipe that is more than 10 years old as Type
L pipe is encountered in the normal course of operations. It is reasonable to expect that the replacements
under this project authorization would not be completed within five years. During Year 2, O exceeds its
capital maintenance budget in State Y by $1 million.
A review of the work orders charged to the project
authorization during Year 2 indicates that O spent $2
million on replacing 12 miles of functional Type L
distribution mains. One work order authorized the
replacement of six miles of distribution mains at different locations within ZIP Code delivery Area H at
a cost of $ 1.2 million. The remaining three work
orders each authorized the replacement of two miles
of distribution mains at different locations within ZIP
Code delivery Area J.
(ii) For purposes of determining whether the
replacement costs are capitalized under section 5.03
of this revenue procedure, the replacements of Type
L distribution mains in State Y in Year 2 are not
aggregated under this section 5.06 under O’s written project authorization, because the written project
authorization does not specify the amount of mains
or the total cost of replacements, or the period over
which the replacements are to occur and it is reasonable to expect that the replacements will not be
completed within five years. However, the replacement of six miles of distribution mains pursuant to
the work order charged in Year 2 authorizing the
replacement of six miles of distribution mains at
specified locations within ZIP Code delivery Area
H is aggregated under this section 5.06 because this
work order meets the requirements of section 5.06(1)
of this revenue procedure and constitutes an authorizing document. See section 5.06(3) of this revenue
procedure. Although the other three work orders
are for replacements of distribution mains within
the same ZIP Code delivery area, these work orders
are not aggregated because they constitute separate authorizing documents. Because each of these
three work orders is for the replacement of less than
four miles of distribution mains, the costs of these
distribution main replacements are not required to
be capitalized under section 5.03 of this revenue
procedure.
(g) Example 7. (i) M is a natural gas distribution
company. M budgets $10 million for the replacement
of distribution mains that run through subdivisions
A and B, which are in ZIP code delivery area H. The
budget directs the work to be done through a written project authorization, which is issued in Year 1.
The work under the written project authorization is
reasonably expected to be completed in late Year 2
or early Year 3. The priority of replacements will
be determined based on risk assessments, but the

May 1, 2023

written project authorization calls for the eventual
replacement of five miles of distribution mains in
ZIP code delivery area H.
(ii) For purposes of determining whether the
replacement costs are capitalized under section
5.03 of this revenue procedure, aggregation is not
required by the general budget because the budget
does not qualify as an authorizing document under
section 5.06(2) of this revenue procedure. However,
the replacements done pursuant to the written project authorization are aggregated under this section
5.06 because the document is aimed at a specific
purpose, authorizes the replacement of a known
amount of distribution mains in a certain location
and, although it does not specify the time period over
which replacements will be completed, there is no
reason to expect that completing the replacements
will take longer than five years. Because the aggregate replacements of distribution mains within ZIP
Code area H total more than four miles, the costs to
replace the five miles of distribution mains are capitalized under section 5.03 of this revenue procedure.
(h) Example 8. (i) L is a natural gas transmission
company that operates a natural gas transmission
line in State C. In Year 1, L conducts an internal
inspection of a 100-mile section of the transmission
line, a hydraulic subsystem that is a separate unit of
property under section 5.02(1) of this revenue procedure. An analysis of the survey indicates that 11
miles (11 percent) of the pipe in this section should
be removed and replaced due to deterioration. In a
written project authorization issued in January of
Year 1, L’s management authorized $22 million to
replace the 11 miles of pipe and directed that the
work commence as soon as practicable. The project
is expected to be completed in Year 1. Based on a
study of actual deterioration in removed pipe versus
the deterioration shown by the inspection device, L’s
engineers determine in November of Year 1 that the
replacement of only nine miles (9 percent) is warranted. The replacement of the nine miles, which was
performed under two separate work orders, is completed in December of Year 1.
(ii) For purposes of determining whether the
replacement costs are capitalized under section 5.02
of this revenue procedure, the replacements are
required to be aggregated under this section 5.06
pursuant to the January, Year 1, authorization, which
meets the requirements of section 5.06(1) and (2) of
this revenue procedure. Under section 5.06(5) of this
revenue procedure, the aggregation determination is
based on the status of the written project authorization and the work done, or to be done, at the end of
each taxable year. As of the end of Year 1, it was
known that only nine miles of the transmission line
were replaced. Because the aggregated replacements
total less than 10 percent of the unit of linear transmission property, the cost of the replacements is not
required to be capitalized under section 5.02 of this
revenue procedure.
(i) Example 9. (i) The facts are the same as in
Example 8, except that the January Year 1 project
authorization required the replacement of only nine
miles (9 percent) of L’s 100-mile hydraulic subsystem. In November of Year 1, L’s engineers then
determined that a total of 11 miles (11 percent) had
to be replaced, and the replacement of 11 miles was
completed in December of Year 1.

816

(ii) For purposes of determining whether the
replacement costs are capitalized under section 5.02
of this revenue procedure, the replacement work
is aggregated pursuant to the January Year 1 project authorization, which meets the requirements of
section 5.06(1) and (2) of this revenue procedure.
Under section 5.06(5) of this revenue procedure,
the aggregation determination is based on the status of the written project authorization and the work
done, or to be done, at the end of each taxable year.
It was known as of the end of Year 1 that more than
10 percent of the unit of property was replaced, as
aggregated under this section 5.06 pursuant to the
January Year 1 project authorization. Accordingly,
the cost of the replacements in Year 1 must be capitalized under section 5.02 of this revenue procedure.
(j) Example 10. (i) The facts are the same as in
Example 8, except that when the January Year 1
written project authorization is issued, L’s management expects that the work will not be completed
until Year 3. The work commences in Year 1 and
continues in Years 2 and 3. In Year 3, based on a
study of actual deterioration in removed pipe versus
that shown by the inspection device, L’s engineers
determine that the replacement of only nine miles (9
percent) of the 100-mile section is warranted, rather
than the 11 miles (11 percent) originally anticipated.
In December of Year 3, L’s engineers issue the final
work order, authorizing the replacement of two additional miles of pipe, and the work is completed. In
aggregate, only nine total miles of pipe are replaced
under the written project authorization.
(ii) For purposes of determining whether the
replacement costs are capitalized under section 5.02
of this revenue procedure, the replacement work
expected to be performed in Year 1, Year 2, and Year
3 is aggregated pursuant to the January Year 1 project authorization, which meets the requirements of
sections 5.06(1) and (2) of this revenue procedure.
Because the replacement of more than 10 percent
of the unit of property was authorized in January of
Year 1, the costs of the replacements that are incurred
in Year 1 and Year 2 are capitalized. Under section
5.06(5) of this revenue procedure, the aggregation
determination is based on the status of the written
project authorization and the work done, or to be
done, as of the close of each taxable year, and modifications do not affect the aggregation of replacements
in prior taxable years. Therefore, the fact that only a
total of nine miles (nine percent of the 100-mile unit
of property) was eventually replaced does not affect
the tax treatment of the replacement costs incurred
in Year 1 and Year 2. However, the costs incurred in
Year 3 are not required to be capitalized because, at
the end of Year 3, L knows that only nine percent of
the unit of property was replaced under the Year 1
project authorization.
(k) Example 11. (i) The facts are the same as in
Example 10, except that pursuant to L’s initial survey, the January Year 1 written project authorization
requires the replacement of only nine miles of pipe
(nine percent of the 100-mile unit of property). Eight
miles are replaced in Years 1 and 2. In Year 3, L’s
engineers determine that five additional miles of
pipe should be replaced for a total of 13 miles and
request that management modify the project and
authorize additional funds to complete the 13-mile
replacement. The project authorization is modified

Bulletin No. 2023–18

accordingly, and replacement of the remaining five
miles is completed by December of Year 3.
(ii) For purposes of determining whether the
replacement costs are capitalized under section 5.02
of this revenue procedure, the costs of the replacements expected to be performed in Years 1 through
3 were aggregated under this section 5.06 pursuant
to the Year 1 project authorization, which meets
the requirements of sections 5.06(1) and (2). Under
section 5.06(5) of this revenue procedure, the aggregation determination was based on the status of the
written project authorization and the work done, or
to be done, as of the close of each taxable year, and
modifications would not affect the aggregation of
replacements in prior taxable years. Accordingly, the
costs incurred in Years 1 and 2 are not required to be
capitalized because, as of the end of each of those
taxable years, the total replacements required by the
project authorization were not expected to exceed 10
percent of the unit of property. Pursuant to section
5.06(5) of this revenue procedure, however, the cost
of the five miles replaced in Year 3 is required to be
capitalized, because, as of the end of Year 3, it was
known that a total of 13 miles (13 percent of the unit
of property) were replaced pursuant to the Year 1
project authorization.

.07 Safe harbor method for linear
property – rules for distribution service
line costs.
(1) In general. A taxpayer using the
safe harbor method for linear property
must determine the amount of distribution
service line costs that must be capitalized using the rules described in sections
5.07(2) and 5.07(3) of this revenue procedure. The rules in section 5.07(2) of this
revenue procedure determine the treatment of distribution service line costs that
a taxpayer can identify with reasonable
accuracy as paid or incurred for a project described in section 5.07(2) of this
revenue procedure. The rules in section
5.07(3) of this revenue procedure determine the treatment of distribution service
line costs that the taxpayer is unable to
identify with reasonable accuracy as paid
or incurred for a project described in section 5.07(2) of this revenue procedure.
(2) Rules for identified distribution
service line costs. To the extent that a
taxpayer can identify, with reasonable
accuracy, distribution service line costs,
the following treatment applies to the
identified costs:
(a) Identified costs that are per se capital expenditures. Identified distribution
service line costs that are per se capital
expenditures described under section
5.05 of this revenue procedure, including
distribution service line costs associated
with distribution main costs that are per

Bulletin No. 2023–18

se capital expenditures described under
section 5.05 of this revenue procedure, are
required to be capitalized.
(b) Identified costs other than per se
capital expenditures.
(i) Identified distribution service line
costs, other than per se capital expenditures described in section 5.07(2)(a) of
this revenue procedure, associated with
distribution main replacements that are
required to be capitalized under section
5.03(2) of this revenue procedure (that is,
associated with distribution main replacements that are more than four miles), are
required to be capitalized;
(ii) Identified distribution service line
costs, other than per se capital expenditures described in section 5.07(2)(a) of
this revenue procedure, associated with
distribution main replacements that are
not required to be capitalized under section 5.03(2) of this revenue procedure
(that is, associated with distribution main
replacements that are four miles or less),
are not required to be capitalized; and
(iii) Identified distribution service line
costs, other than per se capital expenditures described in section 5.07(2)(a) of
this revenue procedure, not associated
with distribution main replacements (for
example, the replacement of a customer’s
service line only) are not required to be
capitalized.
(3) Simplified rules for unidentified distribution service line costs. To the extent a
taxpayer cannot identify distribution service line costs with reasonable accuracy
as provided under section 5.07(2) of this
revenue procedure, the simplified rules
in this section 5.07(3) apply to determine
the amount of such costs to be capitalized under §§ 263(a) and 263A. Step 1
determines the total amount of unidentified distribution service line costs. Steps
2 through 4 determine the capitalization
ratio that applies to such costs. In Step 5,
the taxpayer multiplies the total amount of
unidentified distribution line costs determined in Step 1 by the capitalization ratio
to determine the amount of its unidentified distribution service line costs that are
required to be capitalized.
(a) Step 1. Determine total unidentified
distribution service line costs. To determine the total unidentified distribution
service line costs, the taxpayer’s total distribution service line costs for the taxable

817

year are reduced by the identified distribution service line costs described in section
5.07(2) of this revenue procedure.
(b) Step 2. Determine total distribution main replacement costs not
associated with identified distribution
service line costs (denominator of capitalization ratio). To determine the total
distribution main replacement costs not
associated with identified distribution
service line costs for purposes of the
denominator in the capitalization ratio, the
taxpayer’s total distribution main replacement costs, including distribution main
replacement costs qualifying under the de
minimis rule for blanket orders under section 5.03(3)(b) of this revenue procedure,
paid or incurred in the taxable year are
decreased by the following:
(i) Distribution main replacement costs
that are required to be capitalized as per se
capital expenditures under section 5.05 of
this revenue procedure;
(ii) Distribution main replacement
costs associated with identified distribution service line costs required to be
capitalized under section 5.07(2)(b)(i) of
this revenue procedure; and
(iii) Distribution main replacement
costs associated with identified distribution service line costs not required to be
capitalized under section 5.07(2)(b)(ii) of
this revenue procedure.
(c) Step 3. Determine capitalized
distribution main replacement costs
not associated with identified distribution service line costs (numerator of
capitalization ratio). To determine the
capitalized distribution main replacement
costs not associated with identified distribution service line costs for purposes of
the numerator in the capitalization ratio,
the taxpayer’s total costs of distribution
main replacements that are required to
be capitalized under section 5.03(2) of
this revenue procedure are decreased by
any amount of distribution main replacement costs associated with identified
distribution service line costs required to
be capitalized under section 5.07(2)(b)
(i) of this revenue procedure (the amount
determined in section 5.07(3)(b)(ii) of this
revenue procedure).
(d) Step 4. Determine capitalization
ratio. To determine the capitalization
ratio, divide the taxpayer’s capitalized
distribution main replacement costs not

May 1, 2023

associated with identified distribution service line costs that were capitalized, as
determined under Step 3, by the taxpayer’s
total distribution main replacement costs
not associated with distribution service
line costs, as determined under Step 2.

(e) Step 5. Determine the portion of
unidentified distribution service line costs
that must be capitalized. To determine the
portion of unidentified distribution service
line costs that must be capitalized, multiply the taxpayer’s capitalization ratio, as

determined under Step 4, by the taxpayer’s total unidentified distribution service
line costs determined under Step 1.
(f) Formula. The following formula
reflects the rule provided in this section
5.07(3):

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)

×

[

(4) Example.
(a) Facts. K is a corporation that operates a natural gas distribution system in
State D. K files its Federal income tax
return on an accrual method and a calendar year basis and uses the NGSH
Method. K uses work orders and blanket
work orders to authorize replacement and
repair work on its distribution system.
K’s work orders detail the scope of each
individual project and capture direct and
indirect costs for labor, construction, and
materials. K’s work orders for the replacement of distribution mains identify the
distribution service lines that are replaced
in conjunction with these distribution
main replacements.
In Year 1, K incurs costs of $9 million
with respect to replacements of linear
distribution property. Of this amount,
K incurs $8 million for replacements of
distribution mains (including $1 million
in distribution main replacement costs
qualifying under the de minimis rule for
blanket work orders), and K incurs $1 million for distribution service lines costs. Of
the $1 million K incurs for work on distribution service lines, K incurs $150,000
for distribution service line costs that are
per se capital expenditures, including distribution service line costs associated with
distribution mains, the costs of which
are per se capital expenditures. K incurs
$60,000 for distribution service line costs
that are capitalized under the NGSH
Method because they are associated with
distribution main replacements of more
than four miles, and K incurs $140,000 for

May 1, 2023

Capitalization ratio (Step 4)
distribution service line costs that are not
required to be capitalized under the NGSH
Method because they are associated with
distribution main replacements of four
miles or less. K also incurs $100,000 for
distribution service line costs, other than
per se capital expenditures, not associated
with distribution main replacements. Of
the $8 million K incurs for replacement
of distribution mains, K incurs $2 million
for per se capital expenditures related to
distribution mains, $1.5 million for distribution main replacements exceeding four
miles, and $3.5 million for distribution
main replacements of four miles or less. K
can associate $600,000 of the $1.5 million
K incurs for distribution main replacements exceeding four miles with identified
distribution service line costs that are capitalized under section 5.07(2)(b)(i) of this
revenue procedure. K can also associate
$2.5 million of the $3.5 million K incurs
for distribution main replacements of four
miles or less with identified distribution
service line costs that are not required to
be capitalized under section 5.07(2)(b)(ii)
of this revenue procedure.
(b) Step 1. To determine its total
unidentified distribution service line costs,
K begins with the $1 million it incurs for
its work on distribution service lines for
Year 1 and subtracts its identified distribution service line costs for Year 1.
These identified distribution service lines
costs are the sum of (i) $150,000, K’s
distribution service line costs that are
per se capital expenditures under section
5.07(2)(a) of this revenue procedure, (ii)

818

]

=

$60,000, K’s distribution service line
costs that are capitalized under section
5.07(2)(b)(i) of this revenue procedure
because they are associated with distribution main replacements of more than
four miles, (iii) $140,000, K’s distribution
service line costs that are not capitalized
under section 5.07(2)(b)(ii) of this revenue procedure because they are associated
with distribution main replacements of
four miles or less, and (iv) $100,000, K’s
distribution service line costs that are
identified under section 5.07(2)(b)(iii) of
this revenue procedure as not associated
with any distribution main replacements.
Thus, K’s total identified distribution service line costs equals $450,000 ($150,000
+ $60,000 + $140,000 + $100,000). K
subtracts the total identified distribution service line costs of $450,000 from
the total distribution service line costs it
incurs for the taxable year of $1 million.
The net result of $550,000 ($1 million
– $450,000) is the total unidentified distribution service line costs.
(c) Step 2. K then determines the total
distribution main replacement costs not
associated with identified distribution
service line costs by taking the total costs
incurred in Year 1 with respect to distribution main replacement property of $8
million (which includes the $1,000,000
for expenditures of less than $50,000 on
blanket work orders qualifying under the
de minimis rule) and decreasing these
costs by (i) $2 million, the distribution
main replacement costs that are per se
capital expenditures under section 5.05

Bulletin No. 2023–18

of this revenue procedure; (ii) $600,000,
the distribution main replacements costs
associated with identified distribution
service line costs that are capitalized
under section 5.07(2)(b)(i) of this revenue procedure; and (iii) $2.5 million,
the distribution main replacements costs
associated with identified distribution service line costs that are not required to be
capitalized under section 5.07(2)(b)(ii) of
this revenue procedure. The net result of
$2.9 million ($8 million – ($2 million +
$600,000 + $2.5 million)) comprises the
total distribution main replacement costs
not associated with identified distribution
service line costs.
(d) Step 3. Next, K determines the to

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/agency%3Airs%3Af2a0f412d3dd4fb0. Public record. Not legal advice.