Standard Oil Co.
v.
Comm'r of Internal Revenue

United States Tax CourtAug 12, 1981
77 T.C. 349 (U.S.T.C. 1981)
77 T.C. 349T.C.

Docket No. 5319-76.

1981-08-12

STANDARD OIL COMPANY (INDIANA), PETITIONER v. COMMISSIONER of INTERNAL REVENUE, RESPONDENT

Glenn L. Archer , Jr. , Richard M. Roberts , and William H. Bradford, Jr. , for the petitioner. Seymour I. Sherman and Robert R. Rubin , for the respondent.


On its income tax returns, petitioner capitalized the following costs of constructing offshore jacket-type drilling platforms: labor, fuel, repairs, hauling, supplies, and overhead. In its petition, it claims these costs are deductible as intangible drilling costs (IDC). Held, claiming such costs as deductions does not constitute a change in the method of accounting under sec. 446(e), I.R.C. 1954, requiring the consent of the Commissioner. Held, further: The jacket-type drilling platforms involved here are not ordinarily considered as having salvage value. Accordingly, all of the other costs in issue incurred in constructing the platforms (except for certain “conductor pipe”) are “at risk” in the drilling ventures and are deductible as IDC under sec. 1.612-4, Income Tax Regs.

Petitioner claimed the investment credit on new service station identification signs and lighting facilities which the Commissioner contends do not constitute “section 38 property.” Held, the components of the signs and lighting systems constitute “section 38 property,” and petitioner is entitled to the investment credit under sec. 38, I.R.C. 1954, except as to concrete foundations embedded in the soil to which poles for signs and lights are bolted and as to poles embedded in concrete bases to which are attached signs and lights.

Petitioner, on its income tax returns, treated the signs and lighting components as “section 1250 property” and claimed maximum depreciation of 150 percent under the declining balance method of depreciation for new signs and lights and claimed straight line depreciation for the used signs and lights. Having reclassified most of the signs and lights as personal property, petitioner now claims increased depreciation under the sum of the years-digits method of depreciation for new signs and lights and the 150-percent declining balance depreciation method for the used signs and lights. Held, such a change in computing depreciation is a change in the method of accounting for which petitioner did not obtain the consent of the Commissioner and is not permissible.

Petitioner claimed that the minimum tax on tax preference items is an excise, deductible as an ordinary and necessary business expense. Held, the minimum tax on tax preference items is a Federal income tax, not an excise, and is, therefore, not deductible. Graff v. Commissioner, 74 T.C. 743 (1980). Glenn L. Archer, Jr., Richard M. Roberts, and William H. Bradford, Jr., for the petitioner. Seymour I. Sherman and Robert R. Rubin, for the respondent.

GOFFE , Judge:

The Commissioner determined deficiencies in petitioner's Federal income tax for its taxable years ending December 31 of 1970 and 1971 in the respective amounts of $7,402,139.81 and $6,372,883.57. Petitioner moved, on the basis of our decision in Standard Oil Co. (Indiana) v. Commissioner, 68 T.C. 325 (1977), for summary judgment as to those deductions for intangible drilling and development costs (herein IDC) expended in the drilling of offshore wells from mobile drilling rigs which the Commissioner had disallowed. Respondent failed to allege any material facts which would distinguish such expenditures from the expenditures held deductible in that prior case, and we granted petitioner's motion as to those items. The issues remaining for our decision are:

(1) Whether three of petitioner's subsidiaries may deduct as IDC under section 263(c), I.R.C. 1954, certain costs of fabricating offshore drilling platforms;

Outer Continental Shelf lease with the U.S. Department of the Interior.

Drilled from mobile drilling rig and re-entered and completed from platform.

All section references are to the Internal Revenue Code of 1954 as amended.

(2) Whether two of petitioner's subsidiaries are entitled to investment tax credits under section 38 for the taxable year 1971 attributable to their investment in new service station signs and lighting facilities;

(3) Whether such signs and lighting facilities are subject to depreciation under a method not chosen when such items were placed into service; and

(4) Whether the minimum tax on tax preference items (secs. 56 through 58) is deductible.

FINDINGS OF FACT

Some of the facts have been stipulated. The stipulations of facts and attached exhibits are incorporated herein by this reference.

Standard Oil Co. (Indiana) (herein Standard or petitioner) had its principal office and place of business in Chicago, Ill., at the time it filed its petition herein. Petitioner, together with members of its affiliated group, filed consolidated Federal income tax returns for its taxable years 1970 and 1971 with the District Director of Internal Revenue at Chicago, Ill. Standard and its affiliates are engaged on a worldwide basis in the exploration for, and the development, production, purchase, and transportation of, crude oil and natural gas. They are also engaged in the manufacture, transportation, and marketing of petroleum products, including chemicals.

Issue 1. Offshore Platforms Intangible Drilling and Development Costs

Amoco Production Co., a corporation organized under the laws of the State of Delaware (hereinafter called Amoco Production) (formerly Pan American Petroleum Corp.) was, at all times here pertinent, a wholly owned subsidiary of petitioner, and was engaged in the business of acquiring, exploring, and developing oil and gas properties in the United States and in offshore U.S. waters, and in producing and selling its share of oil and gas from such properties. Amoco (U.K.) Exploration Co., a corporation organized under the laws of the State of Delaware (hereinafter Amoco U.K.) was, at all times here pertinent, a wholly owned subsidiary of petitioner (either directly or through intermediate subsidiaries) and was engaged in the business of acquiring, exploring, and developing oil and gas properties in the offshore waters of the United Kingdom, principally in the North Sea, and in producing and selling its share of oil and gas from such properties. Amoco Trinidad Oil Co., a corporation organized under the laws of the State of Delaware (hereinafter Amoco Trinidad) was, at all times here pertinent, a wholly owned subsidiary of petitioner (either directly or through intermediate subsidiaries), and was engaged in the business of acquiring, exploring, and developing oil and gas properties in offshore Trinidad waters, and in producing and selling its share of oil and gas from such properties.

Prior to the taxable years 1970 and 1971, and effective at all times here pertinent, Amoco Production, Amoco U.K., and Amoco Trinidad (hereinafter sometimes referred to in the aggregate as the subsidiaries or the petitioner duly elected to deduct as current expense all intangible drilling and development costs (hereinafter sometimes referred to as IDC) in accordance with section 263(c) of the Code and section 1.612-4, Income Tax Regs.

During the years 1970 and 1971, Amoco Production installed in the Gulf of Mexico five offshore platforms on oil and/or gas properties in which it had a working or operating interest. The year of installation, lease number, area or location of the platform, identifying code or number of the platform, and Amoco Production's proportional working interest in each block were as follows:

+-----------------------------------------------------------------------+ ¦Year ¦ ¦ ¦Platform ¦Working ¦ +-----------+-------------+-----------------------+----------+----------¦ ¦installed ¦Lease No. ¦Location ¦ID No. ¦interest ¦ +-----------+-------------+-----------------------+----------+----------¦ ¦ ¦ ¦ ¦ ¦ ¦ +-----------+-------------+-----------------------+----------+----------¦ ¦1970 ¦OCS-G—0987 1 ¦Eugene Island block 273¦E.I. 273-B¦50% ¦ +-----------+-------------+-----------------------+----------+----------¦ ¦1970 ¦OCS-G—0971 1 ¦East Cameron block 261 ¦E.C. 261-A¦60% ¦ +-----------+-------------+-----------------------+----------+----------¦ ¦1971 ¦OCS—0829 1 ¦Ship Shoal block 219 ¦S.S. 219-B¦50% ¦ +-----------+-------------+-----------------------+----------+----------¦ ¦1971 ¦OCS-G—1085 1 ¦West Delta block 75 ¦W.D. 75-D ¦75% ¦ +-----------+-------------+-----------------------+----------+----------¦ ¦1971 ¦OCS-G—1069 1 ¦West Delta block 35 ¦W.D. 35-B ¦60% ¦ +-----------+-------------+-----------------------+----------+----------¦ ¦ ¦ ¦ ¦ ¦ ¦ +-----------------------------------------------------------------------+

During 1971, Amoco U.K. installed an offshore platform (herein Leman-D) on an oil and/or gas property known as block 4 9/27 (Leman Field) in the United Kingdom sector of the North Sea. Amoco U.K. held a working interest therein of 29.12483 percent.

During the years 1970 and 1971, Amoco Trinidad installed in offshore Trinidad waters three offshore platforms on oil and/or gas properties acquired under a license from the Government of Trinidad. The year installed, area description, and platform identification are as follows:

+-------------------------------------------------+ ¦Year installed ¦Area description ¦Platform ID ¦ +----------------+------------------+-------------¦ ¦ ¦ ¦ ¦ +----------------+------------------+-------------¦ ¦1970 ¦Teak ¦Teak-A ¦ +----------------+------------------+-------------¦ ¦1971 ¦Teak ¦Teak-B ¦ +----------------+------------------+-------------¦ ¦1971 ¦Samaan ¦Samaan-A ¦ +-------------------------------------------------+ Amoco Trinidad owned 100 percent of the working interest in each of the above properties.

Following the installation of the foregoing nine offshore platforms, oil and/or gas wells were drilled from each platform. Each of the nine platforms was incident to and necessary for the drilling of such wells and the preparation of such wells for the production of oil and/or gas.

The following is a schedule with respect to each of the five offshore platforms installed in the Gulf of Mexico by Amoco Production during the years 1970 and 1971 showing the platform identification number, the wells drilled from each platform, the spud dates of the wells, the dates such wells were completed (if they were completed), and the status of such wells. Where wells from the same platform have the same first digit, such designation indicates multiple completions in the same well.

+---------------------------------------------------------------------+ ¦ ¦ ¦ ¦Completion ¦Status ¦ +----------+----------+-----------+------------+----------------------¦ ¦Platform ¦Well No. ¦Spud date ¦date ¦as of 9/30/79 ¦ +----------+----------+-----------+------------+----------------------¦ ¦ ¦ ¦ ¦ ¦ ¦ +----------+----------+-----------+------------+----------------------¦ ¦E.I. 273—B¦1 ¦9/ 3/70 ¦ ¦Operation suspended ¦ +----------+----------+-----------+------------+----------------------¦ ¦ ¦2 ¦10/29/70 ¦4/ 6/71 ¦Flowing gas ¦ +----------+----------+-----------+------------+----------------------¦ ¦ ¦2D ¦10/29/70 ¦4/ 6/71 ¦Flowing gas ¦ +----------+----------+-----------+------------+----------------------¦ ¦ ¦3 ¦12/ 6/70 ¦1/15/71 ¦Shut-in gas ¦ +----------+----------+-----------+------------+----------------------¦ ¦ ¦4 ¦9/30/70 ¦5/14/71 ¦Shut-in gas ¦ +----------+----------+-----------+------------+----------------------¦ ¦ ¦5 ¦11/14/70 ¦7/ 5/71 ¦Flowing gas ¦ +----------+----------+-----------+------------+----------------------¦ ¦ ¦6 ¦1/24/71 ¦3/17/71 ¦Flowing gas ¦ +----------+----------+-----------+------------+----------------------¦ ¦ ¦6 ¦1/24/71 ¦3/17/71 ¦Abandoned ¦ +----------+----------+-----------+------------+----------------------¦ ¦ ¦6D ¦1/24/71 ¦3/17/71 ¦Authorized abandonment¦ +----------+----------+-----------+------------+----------------------¦ ¦ ¦7 ¦4/ 6/71 ¦5/ 4/71 ¦Shut-in gas ¦ +----------+----------+-----------+------------+----------------------¦ ¦ ¦7D ¦4/ 6/71 ¦5/ 4/71 ¦Shut-in gas ¦ +----------+----------+-----------+------------+----------------------¦ ¦ ¦8 ¦5/15/71 ¦--- ¦Plugged and abandoned ¦ +---------------------------------------------------------------------+

E.C. 261—A 1 7/ 1/66 1 6/ 9/71 Shut-in gas 1D 7/ 1/66 1 6/ 9/71 Flowing gas 2 12/ 6/70 3/18/71 Abandoned 2D 12/ 6/70 3/18/71 Authorized for 1 ndonment 3 11/ 5/70 12/ 5/70 Authorized for 1 ndonment 3 11/ 5/70 2/20/71 Abandoned 3D 11/ 5/70 2/20/71 Flowing gas 4 9/23/70 2/ 4/71 Flowing gas 5 12/23/70 1/28/71 Flowing gas 6 3/18/71 5/23/71 Shut-in gas 6D 3/18/71 5/23/71 Shut-in gas

S.S. 219—B 1 4/17/71 2/26/73 Flowing oil 2 5/24/71 7/ 7/71 Flowing oil 3 10/30/71 2/15/74 Abandoned 4 8/ 2/71 10/29/71 Flowing oil 4D 8/ 2/71 10/29/71 Shut-in oil 5 7/ 8/71 8/ 1/71 Pumping oil 6 11/30/71 12/17/71 Flowing oil 7 9/ 8/71 10/17/71 Abandoned 8 12/20/71 1/11/72 Operations suspended 9 1/12/72 2/21/72 Repairs being made 10 2/22/72 4/26/72 Pumping oil 11 7/30/72 9/17/72 Shut-in oil 11D 7/30/72 9/17/72 Flowing oil 12 6/ 8/72 --- Plugged and abandoned 13 8/13/73 10/ 8/73 Pumping oil 13D 8/13/73 10/ 8/73 Abandoned 14 9/17/72 10/12/72 Repairs being made 15 10/14/72 12/ 1/72 Unsuccessful drilling 16 12/12/72 1/ 8/73 Pumping oil 17 3/16/73 4/22/73 Shut-in oil 18 6/ 2/73 7/ 7/73 Pumping oil 19 2/19/73 3/16/73 Pumping oil 20 4/27/73 6/ 3/73 Flowing oil 21 7/ 5/73 8/13/73 Flowing oil 22 9/19/73 11/ 3/73 Abandoned 23 10/23/73 --- Plugged and abandoned 24 11/ 9/73 --- Plugged and abandoned

W.D. 35—B 1 6/27/71 8/ 1/71 Abandoned 1D 6/27/71 8/ 1/71 Abandoned 2 8/ 1/71 9/14/71 Flowing gas 2D 8/ 1/71 9/14/71 Abandoned 3 8/25/71 10/22/71 Abandoned 4 9/12/78 6/ 7/79 Flowing gas 5 11/22/78 --- Plugged and abandoned 6 1/22/79 5/22/79 Flowing gas

W.D. 75—D 1 5/ 5/70 9/ 8/71 Pumping oil 1D 5/ 5/70 9/ 8/71 Flowing oil 2 9/14/71 2/27/73 Abandoned 2D 9/14/71 2/27/73 Shut-in oil 3 10/ 5/71 10/22/72 Repairs being made 3D 10/ 5/71 10/22/72 Pumping oil 4 1/19/72 2/ 2/72 Pumping oil 4D 1/19/72 2/ 2/73 Shut-in oil 5 12/21/71 --- Plugged and abandoned 6 12/ 3/71 --- Plugged and abandoned 6 12/ 3/71 --- Plugged and abandoned 6D 12/ 3/71 2/29/72 Shut-in oil 6T 12/3/71 2/29/72 Shut-in oil 7 3/ 1/72 3/16/72 Pumping oil 8 2/ 5/72 2/26/72 Pumping oil 9 1/ 6/72 --- Plugged and abandoned 9D 1/ 6/72 2/28/72 Shut-in oil 9T 1/ 6/72 2/28/72 Flowing oil 10 4/ 1/72 11/ 7/72 Shut-in gas 10D 4/ 1/72 11/ 7/72 Shut-in gas 11 3/17/72 3/30/72 Shut-in oil 11D 3/17/72 3/30/72 Pumping oil 12 5/24/72 6/ 7/72 Pumping oil 13 5/ 1/72 5/23/72 Flowing gas 14 8/ 1/72 --- Plugged and abandoned 15 6/30/72 --- Plugged and abandoned 16 6/11/72 6/29/72 Shut-in oil 17 7/17/72 --- Plugged and abandoned 18 11/ 9/72 12/30/72 Shut-in gas

The following is a schedule with respect to the one offshore platform which was installed by Amoco U.K. in the U.K. sector of the North Sea during the year 1971 showing the platform name, wells drilled from the platform, spud dates of the wells, the dates such wells were completed (if they were completed), and the status of the wells.

+--------------------------------------------------------------------+ ¦Leman-D ¦ ¦ ¦ ¦ +----------+-----------+-----------------+---------------------------¦ ¦ ¦ ¦ ¦ ¦ +----------+-----------+-----------------+---------------------------¦ ¦Well No. ¦Spud date ¦Completion date ¦Status as of 6/18/79 ¦ +----------+-----------+-----------------+---------------------------¦ ¦ ¦ ¦ ¦ ¦ +----------+-----------+-----------------+---------------------------¦ ¦1 ¦3/14/72 ¦4/27/72 ¦Gas and condensate producer¦ +----------+-----------+-----------------+---------------------------¦ ¦2 ¦4/28/72 ¦10/30/73 ¦Gas and condensate producer¦ +----------+-----------+-----------------+---------------------------¦ ¦3 ¦6/27/72 ¦8/31/72 ¦Gas and condensate producer¦ +----------+-----------+-----------------+---------------------------¦ ¦4 ¦7/19/72 ¦11/22/72 ¦Gas and condensate producer¦ +----------+-----------+-----------------+---------------------------¦ ¦5 ¦9/ 4/72 ¦10/23/72 ¦Gas and condensate producer¦ +----------+-----------+-----------------+---------------------------¦ ¦6 ¦11/22/72 ¦12/24/72 ¦Gas and condensate producer¦ +----------+-----------+-----------------+---------------------------¦ ¦7 ¦3/18/73 ¦4/21/73 ¦Gas and condensate producer¦ +----------+-----------+-----------------+---------------------------¦ ¦8 ¦2/15/73 ¦3/16/73 ¦Gas and condensate producer¦ +----------+-----------+-----------------+---------------------------¦ ¦9 ¦12/29/72 ¦2/15/73 ¦Gas and condensate producer¦ +----------+-----------+-----------------+---------------------------¦ ¦10 ¦6/12/73 ¦9/30/73 ¦Shut in ¦ +----------+-----------+-----------------+---------------------------¦ ¦11 ¦4/24/73 ¦5/30/73 ¦Temporarily dead ¦ +----------+-----------+-----------------+---------------------------¦ ¦12 ¦6/ 9/73 ¦7/11/73 ¦Gas and condensate producer¦ +--------------------------------------------------------------------+

The following is a schedule with respect to the three offshore platforms which were installed by Amoco Trinidad in the offshore waters of Trinidad during the years 1970 and 1971, showing the platform name, wells drilled from each platform, spud dates of the wells, the dates such wells were completed (if they were completed), and the status of the wells.

+---------------------------------------------------------------+ ¦Teak-A ¦ ¦ ¦ ¦ +----------+-----------+-----------------+----------------------¦ ¦ ¦ ¦ ¦ ¦ +----------+-----------+-----------------+----------------------¦ ¦Well No. ¦Spud date ¦Completion date ¦Status as of 9/30/79 ¦ +----------+-----------+-----------------+----------------------¦ ¦ ¦ ¦ ¦ ¦ +----------+-----------+-----------------+----------------------¦ ¦1A ¦10/25/70 ¦4/22/71 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦2 ¦12/22/70 ¦1/23/71 ¦Water injection ¦ +----------+-----------+-----------------+----------------------¦ ¦3 ¦2/ 6/71 ¦10/16/71 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦4 ¦2/24/71 ¦3/14/72 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦5X ¦5/13/71 ¦3/13/72 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦6 ¦6/28/71 ¦10/26/71 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦7 ¦8/ 4/71 ¦9/30/71 ¦Water injection ¦ +----------+-----------+-----------------+----------------------¦ ¦8 ¦11/ 6/71 ¦12/25/71 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦9 ¦11/21/71 ¦3/10/72 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦10 ¦1/11/72 ¦3/10/72 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦11 ¦2/15/72 ¦3/20/72 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦12 ¦3/24/72 ¦4/28/72 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦13 ¦6/25/72 ¦8/31/72 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦14 ¦9/ 1/72 ¦12/10/72 ¦Producing oil ¦ +---------------------------------------------------------------+

+---------------------------------------------------------------+ ¦Teak-B ¦ ¦ ¦ ¦ +----------+-----------+-----------------+----------------------¦ ¦ ¦ ¦ ¦ ¦ +----------+-----------+-----------------+----------------------¦ ¦Well No. ¦Spud date ¦Completion date ¦Status as of 9/30/79 ¦ +----------+-----------+-----------------+----------------------¦ ¦ ¦ ¦ ¦ ¦ +----------+-----------+-----------------+----------------------¦ ¦1 ¦1/23/72 ¦5/25/72 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦2 ¦4/19/72 ¦--- ¦Plugged and abandoned ¦ +----------+-----------+-----------------+----------------------¦ ¦3A ¦4/25/72 ¦9/ 7/72 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦4X ¦8/14/72 ¦--- ¦Plugged and abandoned ¦ +----------+-----------+-----------------+----------------------¦ ¦5X ¦10/ 1/72 ¦11/17/72 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦6 ¦12/18/72 ¦1/17/73 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦7X ¦1/15/73 ¦3/13/73 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦8 ¦3/24/73 ¦4/16/73 ¦Dry ¦ +----------+-----------+-----------------+----------------------¦ ¦9 ¦4/16/73 ¦5/17/73 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦10 ¦5/18/73 ¦12/20/73 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦11 ¦8/24/73 ¦--- ¦Plugged and abandoned ¦ +---------------------------------------------------------------+

+---------------------------------------------------------------+ ¦Samaan-A ¦ ¦ ¦ ¦ +----------+-----------+-----------------+----------------------¦ ¦ ¦ ¦ ¦ ¦ +----------+-----------+-----------------+----------------------¦ ¦Well No. ¦Spud date ¦Completion date ¦Status as of 9/30/79 ¦ +----------+-----------+-----------------+----------------------¦ ¦ ¦ ¦ ¦ ¦ +----------+-----------+-----------------+----------------------¦ ¦1 ¦8/14/72 ¦10/12/72 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦2 ¦10/10/72 ¦12/ 6/72 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦3 ¦12/ 6/72 ¦12/30/72 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦4 ¦1/18/73 ¦3/16/73 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦5 ¦2/28/73 ¦4/11/73 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦6 ¦4/ 8/73 ¦5/24/73 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦7 ¦5/ 3/73 ¦6/ 7/73 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦8 ¦6/ 5/73 ¦7/ 3/73 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦9 ¦7/ 2/73 ¦7/30/73 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦10 ¦7/29/73 ¦9/ 6/73 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦11 ¦9/ 5/73 ¦10/ 9/73 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦12 ¦10/ 7/73 ¦11/ 9/73 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦13 ¦12/16/73 ¦2/ 7/74 ¦Producing oil ¦ +----------+-----------+-----------------+----------------------¦ ¦14 ¦1/20/74 ¦2/21/74 ¦Producing oil ¦ +---------------------------------------------------------------+

The nine offshore platforms here in controversy were of two basic types, namely, a four-pile tender platform and an eight-pile self-contained platform. A four-pile tender platform is capable of drilling up to eight wells and is called a tender platform because it is necessary to anchor a barge or tender alongside the platform during drilling to accommodate and store part of the drilling pipe and other material and equipment used in the drilling. An eight-pile platform is capable of drilling up to 24 wells (depending on the well spacing and the type of hydrocarbon in the reservoir) and is called self-contained because some or all of the drilling pipe and other material and equipment used in drilling can be accommodated and stored on the platform. The following schedule shows for each platform in controversy the type of platform design, the water depth in which the platform was installed, and the weight in tons of the deck section, the jacket section, the pilings, and the total weight.

+-----------------------------------------------------------------------------+ ¦Platform ¦ ¦Water ¦Tonnage ¦ +-----------------+------------------+-------+--------------------------------¦ ¦description ¦Type of platform ¦depth ¦Jacket ¦Deck ¦Piling ¦Total ¦ +-----------------+------------------+-------+--------+------+--------+-------¦ ¦ ¦ ¦ ¦ ¦ ¦ ¦ ¦ +-----------------+------------------+-------+--------+------+--------+-------¦ ¦Amoco Production:¦ ¦ ¦ ¦ ¦ ¦ ¦ +-----------------+------------------+-------+--------+------+--------+-------¦ ¦ ¦ ¦ ¦ ¦ ¦ ¦ ¦ +-----------------+------------------+-------+--------+------+--------+-------¦ ¦E.I. 273—B ¦4-pile tender ¦184' ¦370 ¦200 ¦540 ¦1,110 ¦ +-----------------+------------------+-------+--------+------+--------+-------¦ ¦E.C. 261—A ¦4-pile tender ¦160' ¦255 ¦200 ¦320 ¦775 ¦ +-----------------+------------------+-------+--------+------+--------+-------¦ ¦S.S. 219—B ¦8-pile ¦117' ¦765 ¦556 ¦1,337 ¦2,658 ¦ +-----------------+------------------+-------+--------+------+--------+-------¦ ¦W.D. 75—D ¦8-pile ¦172' ¦1,502 ¦590 ¦1,749 ¦3,841 ¦ +-----------------+------------------+-------+--------+------+--------+-------¦ ¦W.D. 35—B ¦4-pile tender ¦70' ¦220 ¦210 ¦281 ¦711 ¦ +-----------------------------------------------------------------------------+

Amoco U.K.: Leman-D 8-pile 74' 428 573 444 1,445

Amoco Trinidad: Teak-A 8-pile 185' 642 573 805 2,020 Teak-B 8-pile 190' 809 633 815 2,257 Samaan-A 8-pile 180' 733 540 949 2,222

Prior to the time when the installation of an offshore platform at the desired location is completed, there are four phases of operation which may be described as follows: (1) The fabrication or construction phase (including the designing of the platform prior to commencement of onshore construction); (2) the load-out or tie-down phase, consisting essentially of the removal of the platform from the shipyard or other site or facility where it was constructed and its preparation for transportation to the desired location; (3) the transportation phase, consisting of the transportation of the platform to the desired location; and (4) the installation phase, consisting of positioning, erecting, and anchoring the platform at the desired location.

Each of the nine platforms consisted of three major units which were constructed separately onshore: (1) The deck, (2) the jacket, and (3) the pilings. The deck section, which bears the equipment necessary for drilling, was usually fabricated as one unit. In some cases, the weight limitations of available lifting equipment required that large open spaces be left in the deck floor. After installing the deck during the installation phase, steel plate or other decking was lifted into the open areas and welded into place. The jacket was also fabricated as one unit. It acted as the support for the deck and consisted of cross-braced tubular steel legs, either four or eight for the platforms involved, through which the pilings can be inserted. The legs, as well as any crossbracing in excess of 24 inches in diameter, were fabricated from flat steel plate and welded along the seams and at the joints. Crossbracing of 24 inches or less in diameter consisted of construction grade steel pipe welded at the joints and brace points. The pilings, also consisting of large tubular members fabricated from flat steel plate, were designed to be inserted through the hollow jacket legs and driven into the sea floor to anchor the platform in position. The pilings were constructed in several sections which were welded together during the installation phase. To further secure the jacket to the pilings, a cement grout is pumped into the annular space between the outside of the pilings and the inside of the jacket legs until such space is filled with cement from top to bottom. The cement hardens and the jacket and pilings are almost irreversibly bonded together. In order to reuse a jacket, one would have to cut the pilings and grout out of the hollow jacket legs so that new pilings could be driven through the legs of the salvaged jacket.

Each of the subsidiaries, as operator of the respective oil and/or gas properties here involved, selected (with the concurrence of the other working interest owners in the case of Amoco Production and Amoco U.K.) the location for each of its offshore platforms. Each platform was constructed for the specific location at which it was to be installed. No two platforms have the same design criteria. The subsidiary's design and engineering personnel gathered information with respect to the proposed platform site and developed the basic design criteria for each specific platform, including water depths, tides, storm ratings, wave forces, soil conditions, well spacing, number and depth of wells desired, size and configuration of the drilling rig to be used, the loads imposed by the wells and lateral loads, types, strength and thickness of steels, size of members, type of bracing, and other data and information from computer-generated design programs. On the basis of this information, the subsidiary had detailed plans and specifications prepared by independent design consultants or, in some instances, by a construction contractor's engineering department. All of the resulting detailed plans, specifications, calculations, etc., were thoroughly reviewed and checked by the staff of the subsidiary before being approved for construction.

A bid document or negotiated procurement package consisting of the detailed drawings, plans, and specifications (usually including paint and welding specifications or instructions), was prepared to obtain prices from the proposed construction contractors invited to bid or negotiate for the work. Each platform in issue was built by an independent construction contractor as follows:

+-----------------------------------------------------------------------------+ ¦Name of contractor ¦Address ¦Platform ¦ +--------------------------------------------------+--------------+-----------¦ ¦ ¦ ¦ ¦ +--------------------------------------------------+--------------+-----------¦ ¦J. Ray McDermott & Co., Inc ¦New Orleans, ¦E.I. 273—B ¦ ¦ ¦LA ¦ ¦ +--------------------------------------------------+--------------+-----------¦ ¦Avondale Shipyards, Inc ¦New Orleans, ¦E.C. 261—A ¦ ¦ ¦LA ¦ ¦ +--------------------------------------------------+--------------+-----------¦ ¦J. Ray McDermott & Co., Inc ¦New Orleans, ¦S.S. 219—B ¦ ¦ ¦LA ¦ ¦ +--------------------------------------------------+--------------+-----------¦ ¦Avondale Shipyards, Inc ¦New Orleans, ¦W.D. 75—D ¦ ¦ ¦LA ¦ ¦ +--------------------------------------------------+--------------+-----------¦ ¦Fluor Ocean Services, Inc ¦New Orleans, ¦W.D. 35—B ¦ ¦ ¦LA ¦ ¦ +--------------------------------------------------+--------------+-----------¦ ¦De Groot Zwijndrecht, N.V ¦Rotterdam, ¦Leman ¦ ¦ ¦Holland ¦Field-D ¦ +--------------------------------------------------+--------------+-----------¦ ¦Heerema Engineering Service ¦The Hague, ¦Teak-A ¦ ¦ ¦Holland ¦ ¦ +--------------------------------------------------+--------------+-----------¦ ¦(Fabrication phase subcontracted to De Groot ¦Rotterdam, ¦ ¦ ¦Zwijndrecht, N.V.) ¦Holland ¦ ¦ +--------------------------------------------------+--------------+-----------¦ ¦Ingram Marine, Inc., and Ingram Contractors, Inc ¦Harvey, LA ¦Teak-B ¦ +--------------------------------------------------+--------------+-----------¦ ¦(Fabrication phase subcontracted to Avondale ¦New Orleans, ¦ ¦ ¦Shipyards, Inc.) ¦LA ¦ ¦ +--------------------------------------------------+--------------+-----------¦ ¦Ingram Marine, Inc., and Ingram Contractors, Inc. ¦Harvey, LA ¦Samaan-A ¦ +--------------------------------------------------+--------------+-----------¦ ¦(Fabrication phase subcontracted to Avondale ¦New Orleans, ¦ ¦ ¦Shipyards, Inc.) ¦LA ¦ ¦ +-----------------------------------------------------------------------------+

During the construction phase, the subsidiary designated a project manager or inspector from its staff to be located on site and oversee the work of the construction contractor. This project manager or inspector, together with other engineers from the subsidiary's staff or independent consultants, witnessed and inspected the fabrication procedures, welding, X-ray tests of welds, cathodic protection, painting, and all other aspects of the construction phase and assured that the platform was built to plans and specifications furnished to the contractor. The representative of the subsidiary generally had authority to require the contractor to correct any defective work and to approve any changes in the drawings, plans, and specifications.

In the design and construction of a platform, the practice of the subsidiaries, to the fullest extent possible, was to use materials and components that could be purchased because it was more expensive to have the construction contractor fabricate such items.

All of the nine platforms in issue were designed and constructed as drilling platforms to support the drilling rigs and associated support equipment and facilities. During the drilling of wells, vertical loads on the drilling platform may exceed 1 million pounds. To withstand these loads, a drilling platform is required to be a considerably stronger, more competent platform than a production platform. In 1970 and 1971, a separate production platform was sometimes set alongside the drilling platform, with the two platforms connected in some cases by a bridge.

After being constructed onshore, the three major units of each platform here involved were loaded on a ship or barge for transportation to the platform location. Installation was performed by skidding and/or lifting the jacket off the ship or barge by means of a lifting crane on another ship and properly positioning the jacket at the desired location. The pilings were then driven, until refusal, through the jacket legs, grouted inside the jacket legs, and welded to the top of such legs in order to anchor and support the jacket. The deck section was then lifted, positioned, and welded on the pilings and jacket legs. Each of the nine offshore platforms installed by the subsidiaries during the years 1970 and 1971 was a jacket type platform.

With respect to each of the platforms in controversy, costs were incurred in the first (construction or fabrication) phase for materials acquired from outside sources and for other costs such as labor, fuel, repairs, hauling, supplies, etc., and an allocable portion of overhead or profit (hereinafter for convenience, all costs not incurred for materials acquired from outside sources will be referred to as “other” costs). The “other” costs incurred during the last three phases (load-out and tie-down, transportation, and installation) were currently deducted as IDC in the returns for 1970 and 1971, except for certain of such costs claimed in the petition herein. None of the costs deducted as IDC in the returns have been disallowed, and the additional costs claimed in the petition have now been allowed. Petitioner now contends that the “other” costs incurred in the first phase are also deductible by it as IDC, and it is only these costs that are in dispute. Such costs were capitalized in petitioner's returns for 1970 and 1971, and in its returns for all prior years beginning no later than 1960.

Petitioner filed petitions with this Court for prior taxable years as follows:

+-----------------------------------+ ¦Docket No. ¦Taxable years ¦ +------------+----------------------¦ ¦ ¦ ¦ +------------+----------------------¦ ¦4023-70 ¦1960, 1961, 1962, 1963¦ +------------+----------------------¦ ¦1342-72 ¦1964, 1965, 1966 ¦ +------------+----------------------¦ ¦9184-73 ¦1967, 1968, 1969 ¦ +-----------------------------------+ In each respective petition, petitioner alleged error in the capitalization in the returns for such years of such “other” costs in the first (construction or fabrication) phase and claimed such “other” costs as IDC. In the compromise and settlement of these prior cases, the parties agreed that the return treatment of such “other” costs would not be changed. Accordingly, no adjustments to the returns for the taxable years 1970 and 1971 need be made for the 1970 and 1971 depreciation deductions claimed with respect to such “other” costs incurred in prior years.

One issue common to three of petitioner's subsidiaries was tried and decided by this Court in docket No. 9184-73. See Standard Oil Co. (Indiana) v. Commissioner, 68 T.C. 325(1977).
11. Thompson v. Commissioner, T.C. Memo. 1979-153.

For the years 1970 and 1971, Amoco Production's share based on its working interest percentages, of the material costs and other costs in the first (construction or fabrication) phase for the five platforms installed in the Gulf of Mexico, which latter amounts are in issue herein, was as follows:

+-------------------------------------------------------------------------+ ¦ ¦1970 ¦1971 ¦ +----------+-------------------------------+------------------------------¦ ¦Platform ¦ ¦ ¦ ¦ ¦ +----------+-----------+-------------------+----------+-------------------¦ ¦ID No. ¦Material ¦“Other” costs ¦Material ¦“Other” costs ¦ +----------+-----------+-------------------+----------+-------------------¦ ¦ ¦ ¦ ¦ ¦ ¦ +----------+-----------+-------------------+----------+-------------------¦ ¦E.I. 273-B¦$143,207.50¦$114,806.25 ¦0 ¦0 ¦ +----------+-----------+-------------------+----------+-------------------¦ ¦E.C. 261-A¦148,187.40 ¦100,459.20 ¦0 ¦0 ¦ +----------+-----------+-------------------+----------+-------------------¦ ¦S.S. 219-B¦211,582.25 ¦52,917.75 ¦$74,395.25¦$123,474.75 ¦ +----------+-----------+-------------------+----------+-------------------¦ ¦W.D. 75-D ¦0 ¦0 ¦693,930.00¦389.746.69 ¦ +----------+-----------+-------------------+----------+-------------------¦ ¦W.D. 75-B ¦0 ¦4,800.00 ¦146,139.00¦54,173.40 ¦ +-------------------------------------------------------------------------+

For the year 1971, Amoco U.K.'s shares, based on its working interest percentage, of the material costs and the “other” costs in the first (construction or fabrication) phase for the Leman-D platform installed in the North Sea, were $168,861.15 and $135,942.37, respectively.

For the years 1970 and 1971, Amoco Trinidad's material costs and the “other” costs in the first (construction or fabrication) phase for the three platforms installed in offshore Trinidad waters were as follows:

+--------------------------------------------------------------------------+ ¦ ¦1970 ¦1971 ¦ +----------+-------------------------------+-------------------------------¦ ¦Platform ¦ ¦ ¦ ¦ ¦ +----------+-----------+-------------------+-----------+-------------------¦ ¦ID No. ¦Material ¦“Other” costs ¦Material ¦“Other” costs ¦ +----------+-----------+-------------------+-----------+-------------------¦ ¦ ¦ ¦ ¦ ¦ ¦ +----------+-----------+-------------------+-----------+-------------------¦ ¦Teak-A ¦$698,773.85¦$522,858.76 ¦0 ¦0 ¦ +----------+-----------+-------------------+-----------+-------------------¦ ¦Teak-B ¦0 ¦0 ¦$629,174.16¦$455,458.21 ¦ +----------+-----------+-------------------+-----------+-------------------¦ ¦Samaan-A ¦0 ¦0 ¦706,312.62 ¦413,843.70 ¦ +--------------------------------------------------------------------------+

The amounts shown as “other” costs in the paragraphs above include the costs of the rolling and welding of sheet steel into tubing or “cans.” A “can” is a piece of sheet steel that has been rolled to form a pipe, the seam of which is welded. Cans are used to form jacket legs or jacket bracing or pilings.

The machinery necessary for the rolling of sheet steel into cans is massive and quite expensive and is owned by some but not all platform contractors. At the time of the construction of the Leman-D and Teak-A platforms, the De Groot firm did not have such facilities. For the purposes of this case, the cost of such rolling and welding may be deemed to constitute 15 percent of the respective amounts shown as “other” costs.

The construction contract for the Teak-A platform specified that $210,610 of the costs of such platform was for “conductor pipe,” which is casing 30 inches in diameter which is used to conduct the mud used in the drilling of an offshore well back to the platform deck.

All of the Gulf of Mexico leases upon which Amoco Production installed the five Gulf of Mexico platforms here in controversy were executed with the U.S. Department of the Interior, Bureau of Land Management. Under each such lease, Amoco Production is required to remove all structures within 1 year following expiration of the lease. Such expiration, under the terms of each lease, may occur 5 years after the date of the respective lease agreement, and will occur, in any event, upon cessation of production. The obligation of Amoco Trinidad and Amoco U.K. to remove their respective platforms is subject to the laws of the Government having jurisdiction and the terms of the governing lease. At the termination of these two concessions, the respective Governments had the option to take over the platforms.

Offshore oil platforms, including those designated as “drilling” platforms, are long-lived assets, with useful lives in excess of 20 years. The period during which wells are drilled and prepared for production is usually short, relative to the full useful life of the platform. Thereafter, the platform is primarily or solely involved in production for the remainder of its useful life, although from time to time thereafter some reworking of one or more old wells or the drilling of one or more additional wells may occur. During such activities, production will normally continue as to the other existing wells. In addition, even during the drilling of wells, production will normally commence on the first well while additional wells are still being drilled.

All of the platforms in controversy in this case are still in place and are still actively producing oil or gas. None are actively drilling or developing wells, drilling activity having been completed in the early 1970's, with the exception of a short period in late 1978 and 1979 when three additional wells were drilled from platform W.D. 35-B. Since shortly after installation, each platform has been predominantly or entirely involved in production rather than in drilling and development.

Production equipment can be and commonly is located or installed on offshore platforms, including those termed “drilling” platforms in industry usage. Amoco Production has placed production equipment on each of the three 4-pile platforms in the Gulf of Mexico here in controversy.

Both drilling and production platforms normally contain two decks, referred to as the cellar deck and upper deck. The cellar deck is the first level, approximately 55 feet above the water line. The upper deck is approximately 15 or 16 feet above the cellar deck. Different types of equipment are installed on each deck. In the case of “drilling” platforms, the drilling rig and related equipment are placed on the upper deck. The cellar deck sometimes contains production equipment.

A deck section for a basic jacket-type platform in the process of construction, and even after completion and readiness for load-out, hypothetically can be modified for use with a different jacket and at a different location than that originally contemplated. In addition, a partially or fully completed jacket section hypothetically can be modified for use at a different location and with a different deck section than that originally contemplated. All such modifications are undertaken only if they are considered to be economically feasible, taking into consideration their usually great costs.

During and after the construction process, a platform jacket, subject to the same economic constraints, can be modified for use in water depths varying by 10 to 15 feet from the depth anticipated in the original design. Only after the jacket has been installed in place, and if the lifting capacity to raise it does not exist, is it no longer subject to such modification.

Deck sections can be manufactured or prefabricated in advance of knowing the specific location of installation of the platform, though this was not the practice of the subsidiaries. Such a procedure will tend to accelerate drilling projects and reduce “lead time,” and was in use during the 1970's by one major oil company, Conoco, Inc. (hereinafter called Conoco). This is accomplished by designing the platform deck to withstand the most severe requirements that may reasonably be anticipated, which policy is obviously more expensive than designing each platform to specifications.

Under unusual circumstances, a deck section and/or jacket section of an offshore drilling platform, after being installed, has been moved to a different location. Of the 51 drilling platforms of the types here involved operated by Amoco Production in the Gulf of Mexico, Amoco Production moved the deck section from 1 platform to replace the deck section, which had been destroyed by a fire, on another platform. The remaining jacket section was subsequently moved to a different location and converted to use as the jacket for a production platform. Conoco, which has in excess of 120 multiwell platforms in the Gulf of Mexico, relocated 2 platforms, approximately 2 and 4 years after they were originally installed, because the wells at the original locations became dry. One was a shallow-water platform in approximately 30 feet of water, and the other was in approximately 90 feet of water. Both were brought back to shore and extensively modified and reconditioned. Before reinstalling the two platforms at new sites, Conoco had to remove portions of the old piling, which had been grouted inside the jacket legs. This is a tremendously expensive operation. In another instance, Conoco modified a jacket section still in the construction phase which was originally designed for installation as part of a platform at West Cameron 66-C. After such modification, the jacket was installed as part of Conoco's platform at Vermillion 199-G. Of some 500 platforms in the Gulf of Mexico, Shell Oil Co. removed the deck section of 1 platform that sustained hurricane damage approximately 1 year after it had been installed. This deck was brought to shore, significantly modified, and reinstalled on a jacket at a different location. The damaged jacket section of this platform was not reused.

It is unknown whether the Conoco or Shell platforms were comparable to the Amoco platforms.

After a platform has been installed for 10 to 15 years, it cannot be reused and has no salvage value. J. Ray McDermott & Co., Inc., a marine contractor, does not allow any salvage or scrap value to offset the removal cost in bidding on the removal of platforms. Conoco has found that the least expensive procedure for removing platforms that are no longer useful to it, is to have the contractor dispose of them because they do not meet current design criteria and governmental requirements and because the cost of cutting a platform up for scrap after it is brought back to shore exceeds any recoveries from the scrap materials. In the mid-1970's, Amoco Production sought to salvage a new jacket section after its bottom portion sustained storm damage during installation. Bids were requested from 12 contractors, who were asked to quote on the basis of an allowance for salvage value. Of the nine bids received, none quoted any allowance for salvage value. Amoco Production accepted a bid of $445,000 which provided for towing the damaged jacket to deep water and sinking the jacket in an approved dumping location.

Issue 2. Service Station Identification Signs and Lighting Facilities Investment Tax Credit

Some of these facts are also relevant for Issue 3.

At all times here pertinent, the American Oil Co. (Maryland) (hereinafter called Maryland) was a corporation organized under the laws of the State of Maryland and was engaged in the business of refining and marketing petroleum products in most of the States of the United States. All of Maryland's outstanding capital stock was owned by petitioner. At all times here pertinent, Maryland owned or leased numerous gasoline service station properties in the various States in which it marketed petroleum products. In addition, Maryland had jobber and other contractual arrangements, including equipment loan agreements, providing for the sale of its products at numerous other locations, which were neither owned nor leased by Maryland. During the years 1970 and 1971, Maryland purchased and installed on certain of these properties certain service station identification signs and lighting facilities.

At all times here pertinent, the American Oil Co. (Texas) (hereinafter called Texas), a corporation organized under the laws of the State of Texas, was engaged in the business of refining and marketing petroleum products in the State of Texas. All of the outstanding capital stock of Texas was owned by Maryland. At all times here pertinent, Texas owned or leased gasoline service station properties in the State of Texas. In addition, Texas had jobber or other contractual arrangements, including equipment loan agreements, for the sale of its products at other locations, which were neither owned nor leased by Texas. During the years 1970 and 1971, Texas purchased and installed on certain of these properties service station identification signs and lighting facilities.

For convenience, Maryland and Texas are sometimes hereinafter referred to collectively as American.

The total number of service station identification signs and the total number of lighting facilities installed by American during each of the years 1970 and 1971 were as follows:

+---------------------------------------+ ¦ ¦ ¦Number of ¦ +------+-------+------------------------¦ ¦Year ¦Signs ¦lighting installations ¦ +------+-------+------------------------¦ ¦ ¦ ¦ ¦ +------+-------+------------------------¦ ¦1970 ¦1,351 ¦1,518 ¦ +------+-------+------------------------¦ ¦1971 ¦1,388 ¦1,503 ¦ +---------------------------------------+ In the case of lighting facilities, the records of American reflect as one installation both a single lighting fixture and groups of lighting fixtures. Thus, all the lighting fixtures which are installed on a property at the same time are listed above as one installation.

As of December 31, 1970, and December 31, 1971, the total number of service stations serving as outlets for Maryland and Texas, broken down between those as to which both land and building were owned, those as to which the land was leased and the building owned, those as to which both land and building were leased, those neither owned nor leased but subject to equipment loan agreements, and those owned or supplied by jobbers, were as follows:

+----------------------------------------------------------+ ¦ ¦12/31/70 ¦12/31/71 ¦ +------------------------------------+----------+----------¦ ¦ ¦ ¦ ¦ +------------------------------------+----------+----------¦ ¦Land and building owned ¦4,248 ¦4,294 ¦ +------------------------------------+----------+----------¦ ¦Land leased, building owned ¦1,599 ¦1,707 ¦ +------------------------------------+----------+----------¦ ¦Land and building leased ¦6,340 ¦5,926 ¦ +------------------------------------+----------+----------¦ ¦Equipment loan agreement ¦5,506 ¦5,220 ¦ +------------------------------------+----------+----------¦ ¦Outlets owned or supplied by jobbers¦10,170 ¦10,615 ¦ +------------------------------------+----------+----------¦ ¦Total ¦27,863 ¦27,762 ¦ +----------------------------------------------------------+

In leasing stations from other parties, American, at all times pertinent hereto, desired to obtain as short a primary lease term as possible with renewal options up to a maximum of 20 years. The lease agreements typically run for a “primary” term of 1 year, with sufficient successive renewal options in favor of the lessee (Maryland or Texas) to entitle the lessee to possession for 20 years following installation of improvements, should it wish to remain for that length of time. The only limit set by company policy on the total lease period is to discourage a term of more than 20 years, including options, from the date improvements are made to the premises. In its Federal income tax returns, petitioner claimed useful lives of 13 to 16 years for signs and lights installed in 1970 and 1971. One reason Maryland and Texas normally seek leases with short primary terms and successive renewal options, rather than leases with terms commensurate with the actual anticipated or expected term of occupancy, arises from petitioner's budgeting practices. Under these practices and procedures, a dollar of primary term rent is treated as a dollar of capital invested, subject only to normal discount for lapse of time. Accordingly, a lease for a 1-year primary term with 20 successive 1-year renewal options will appear as a much smaller capital investment charged to the budget of the department responsible than would a lease for a 20-year term. Of course, another reason for such leasing arrangements is the flexibility inherent in such a procedure.

Of the 7,939 and 7,633 service stations where American either leased the land or both the land and building in 1970 and 1971, 5,262 and 5,259 stations, respectively, were being leased for terms (exclusive of options) of 1 year or less and the balance were being leased for terms (exclusive of options) in excess of 1 year.

The lease agreements under which Maryland and Texas, as lessees, leased real property owned by others for service station sites or other outlets (whether the building is leased or owned), permitted the lessee (Maryland or Texas) to enter the premises following termination of the lease to remove improvements installed by the lessee. None of such leases required the lessee to remove such improvements following termination, or entitled the lessor either to require removal or obtain reimbursement for the cost of removal.

In 1970 and 1971, American also sold its products to military post exchange locations under short-term bid contracts of from 3 months to a year in duration. In connection with such contracts, American furnished and installed signs at such locations.

During 1970 and 1971, American sold its products to independent jobbers, who distributed the products to their own stations and to other independently owned stations, under agreements normally of from 1 to 5 years in duration. American furnished one sign for each station owned or served by such jobbers, and the jobbers customarily arranged for the installation of such signs.

Jobber sales contracts were formerly written on a year-to-year basis, but were not necessarily limited to a specific number of renewals. In the early 1970's, the practice commenced of writing such contracts for a 5-year term, in anticipation of certain regulatory legislation (now known as the Petroleum Marketers' Practicing Act).

Equipment loan agreements were typically executed with independent owners or operators of service stations or with owners who operated gasoline pumps at other types of business sites, e.g., “mom and pop” roadside grocery stores, which may have desired to sell petitioner's branded products. The lessor of the equipment (Maryland or Texas) retained the same right following termination to enter and remove its property, including improvements, as in the leasing of service station sites. Such agreements were generally terminable by either party on 30 days' notice, but normally provided for a payment to Maryland or Texas by the lessee of the equipment if the arrangement were terminated or expired before the expiration of a stated period of time.

During 1970 and 1971, the service station properties owned, leased, or served by American tended to have between one and (infrequently) two identification signs per property, and the service station properties owned or leased by American tended to have between six and eight lighting facilities per property.

The costs of new service station identification signs and new service station lighting facilities ordered and acquired by Maryland after March 31, 1971, and placed and remaining in service in 1971 were $1,488,549.88 and $1,549,434.96, respectively. Such costs included the costs of signs and poles, lighting fixtures and poles, and labor and materials for installation and erection, including labor and materials for the concrete base or foundation. The costs of new service station identification signs and new service station lighting facilities ordered and acquired after March 31, 1971, by Texas and placed and remaining in service in 1971 were $761.81 and $250, respectively. Such costs included the costs of signs and poles, lighting fixtures and poles, and labor and materials for installation and erection, including labor and materials for the concrete base and foundation.

All identification signs and lighting facilities in controversy had useful lives in excess of 7 years. In its Federal income tax returns for 1970 and 1971, petitioner claimed and was allowed depreciation with respect to signs and lights installed by American in 1970 and 1971 on the basis of a 16-year useful life for 1970 installations and a 13-year useful life for 1971 installations.

Installation of a sign at a new location normally required the following steps:

(a) Locate foundation according to plans, excavate, position anchor bolts, and fill excavation with concrete;

(b) Run electrical wiring underground from building distribution panel to location;

(c) Position pole on anchor bolts, level, and secure to anchor bolts by tightening the nuts;

(d) Mount sign head by bolting to pole;

(e) Complete and connect electrical wiring. The installation steps described above normally required from approximately 8 man-hours of jobsite labor (exclusive of travel) for the 15- to 17-foot signs to 32 man-hours for the 90- to 110-foot signs for step (a); 2 to 3 man-hours irrespective of the size of the sign for step (b); and from 4 man-hours for the 15- to 17-foot signs to 48 man-hours for the 90-to 110-foot signs for steps (c), (d), and (e).

All but three of the poles for the foregoing identification signs were bolted down using anchor bolts embedded in a concrete base or foundation. The identification signs were in turn affixed to the poles by bolts. Three identification signs, each having a cost not in excess of $10,000, including installation, were acquired after March 31, 1971, by Maryland and placed in service in 1971 and were installed by embedding the poles in the concrete base.

Installation at a new location of a sign or light required excavation and the pouring of concrete. The excavation needed for a sign varied, depending upon the size of the sign, from 5 to 8 feet in depth and from a minimum of 30 inches in width to a complex T-shape for the larger signs, requiring approximately 60 yards of concrete.

Lighting facilities were installed on or adjacent to the gasoline pump or dispensing island, or by themselves on the perimeter of the service station. When a lighting facility was installed on or adjacent to the dispensing island, its foundation was poured integrally with that of the island, and it obtained most of its structural strength from the island. In such cases, the depth of excavation was sometimes as shallow as 24 inches. The excavation for the foundation of a lighting facility installed at the perimeter was normally 42 inches deep. Urban sites were often covered by asphalt and concrete, and installation of a sign or light in such an area required that the surface be broken into or through in order to excavate for and pour the foundation. Suburban locations sometimes required landscaping removals or changes. The base or foundation for a sign did not normally protrude above ground level, except to the extent necessary for drainage, generally 1 or 2 inches. The highest point of some lighting facility foundations was, likewise, at or barely above ground level; others were as much as 12 to 14 inches above ground level.

Following the excavation and pouring of concrete for the foundation (including the positioning of anchor bolts), the remaining steps in the installation of signs consisted of running electrical wiring underground from the building distribution panel to the location of the sign; positioning the pole and securing it to the foundation by use of the anchor bolts; bolting the sign head to the pole; and completing and connecting the electrical wiring. The complete installation of a sign required (exclusive of travel time) from just under 14 to 15 man-hours of labor for the smallest signs to around 82 to 83 man-hours of labor for the larger size signs.

Following the excavation and pouring of concrete for the foundation (including the positioning of anchor bolts), the remaining steps in the installation of lighting facilities consisted of running electrical wiring underground from the building distribution panel to the location of the lighting facility; attaching the lighting fixture to the pole; positioning the pole and securing it (with the fixture attached) to the foundation by use of the anchor bolts; and completing and connecting the wiring. Installation of a lighting facility required (exclusive of travel time) from 7 to 9 man-hours of labor.

The removal of an identification sign normally required the following steps:

(a) Disconnect electrical wiring at sign head and at base of pole;

(b) Attach crane to sign head;

(c) Disengage bolts between sign head and pole;

(d) Lower sign head to ground;

(e) Attach crane to pole;

(f) Disengage bolts between pole and base and lower pole to ground. The removal of a sign and pole normally required from approximately 2 man-hours of jobsite labor (exclusive of travel) for the 15- to 17-foot signs to 24 man-hours of jobsite labor for the 90- to 110-foot signs. The removal of 15- to 17-foot signs normally involved a two-man crew, and the removal of a 90- to 110-foot sign normally involved a three- or four-man crew. The approximate cost in 1979 for the removal of a sign and pole ranged from approximately $250 for the 15- to 17-foot signs to $2,000 for the 90- to 110-foot signs. In the course of removal of signs that were bolted to the concrete base or foundation, no damage was normally sustained to the sign, the pole, or the base.

The installation of a lighting facility at a new location normally required the following steps:

(a) Locate foundation according to plans, excavate, position anchor bolts, and fill excavation with concrete;

(b) Run electrical wiring underground from building distribution panel to the location;

(c) Attach lighting fixture to pole by bolts;

(d) Position lighting fixture and pole, as one unit, onto anchor bolts, level, and secure to anchor bolts by tightening the nuts;

(e) Complete and connect electrical wiring. The installation steps described above normally required approximately 2 to 3 man-hours of jobsite labor (exclusive of travel) for step (a), 2 to 3 man-hours for step (b), and 3 man-hours for steps (c), (d), and (e). All poles for service station lights installed in 1970 and 1971 were bolted down using anchor bolts embedded in a concrete base or foundation. The lights were in turn affixed to the poles by bolts.

The removal of a lighting facility normally required the following steps:

(a) Disconnect electrical wiring at light fixture and at base of pole;

(b) Attach crane to pole and light fixture;

(c) Disengage bolts between pole and base and lower pole and light fixture to ground. The removal of a lighting fixture and pole normally required approximately 1 man-hour of jobsite labor (exclusive of travel). Removal of a lighting facility normally involved a two-man crew. The approximate cost in 1979 for the removal of a lighting facility was $60. In the course of removal, no damage was normally sustained to the light, the pole, or the base.

Some parts or components of signs and lights are replaceable or removable. Sign heads or images may be changed or replaced if needed, especially upon the change of petitioner's logo or emblem. During or prior to the taxable period in controversy, petitioner did change its logo to a modernized torch and oval design. During 1970 and 1971, it was engaged in a program of changing its old sign heads to its new logo.

Certain sign or light poles often were replaced or removed by American because of damage, relocation required by zoning or other changes, termination or abandonment of a site or outlet, or termination without renewal of the agreement under which petitioner's branded products had been sold at the site.

American immediately removed its identification signs and sign poles from any service stations, whether owned, leased, or supplied under any of the other types of arrangements, whenever such stations were closed or their affiliation with American terminated. When a service station was closed or its affiliation with American terminated, American either removed its lighting facilities (meaning the pole and fixtures) or sold them to the owner (or to a new owner where the property was to continue as a service station affiliated with another supplier). Neither American nor anyone acting on behalf of American normally removed the foundation of a sign or lighting facility, even upon abandonment or sale of a service station site, or upon the complete termination of other arrangements under which petitioner's products were sold at the site.

The following schedule shows for the years 1970 and 1971 Maryland's costs of service station identification signs and lighting facilities, broken down between the cost of the poles, signs, and lights (fixtures) and the cost of installing and erecting (installation) such identification signs and lighting facilities:

+---------------------------------------------------------------+ ¦Year ¦Description ¦Fixtures ¦Installation ¦Total ¦ +------+-------------+-------------+--------------+-------------¦ ¦ ¦ ¦ ¦ ¦ ¦ +------+-------------+-------------+--------------+-------------¦ ¦1970 ¦Signs ¦$1,368,962.85¦$691,738.70 ¦$2,060,701.55¦ +------+-------------+-------------+--------------+-------------¦ ¦1970 ¦Lights ¦1,346,124.09 ¦745,382.22 ¦2,091,506.31 ¦ +------+-------------+-------------+--------------+-------------¦ ¦1971 ¦Signs ¦1,504,969.53 ¦728,700.07 ¦2,233,669.60 ¦ +------+-------------+-------------+--------------+-------------¦ ¦1971 ¦Lights ¦1,392,850.65 ¦846,733.77 ¦2,239,584.42 ¦ +---------------------------------------------------------------+

The following schedule shows for the years 1970 and 1971 Texas' costs of service station identification signs and lighting facilities, broken down between the cost of the poles, signs, and lights (fixtures) and the cost of installing and erecting (installation) such identification signs and lighting facilities:

+---------------------------------------------------------+ ¦Year ¦Description ¦Fixtures ¦Installation ¦Total ¦ +------+-------------+----------+--------------+----------¦ ¦ ¦ ¦ ¦ ¦ ¦ +------+-------------+----------+--------------+----------¦ ¦1970 ¦Signs ¦$48,170.60¦$24,815.16 ¦$72,985.76¦ +------+-------------+----------+--------------+----------¦ ¦1971 ¦Signs ¦510.41 ¦251.40 ¦761.81 ¦ +------+-------------+----------+--------------+----------¦ ¦1971 ¦Lights ¦155.00 ¦95.00 ¦250.00 ¦ +---------------------------------------------------------+

The installation costs set forth above include material and labor costs of the concrete bases or foundations. The costs to Maryland and Texas in 1970 and 1971 of labor and materials for the concrete bases onto which identification signs and lights were bolted constituted approximately 30 percent of the specified installation cost. Such concrete bases were installed in accordance with American's specifications and were designed to accommodate the requirements of American's service station identification signs and lighting facilities.

In the years 1976 through 1978, American relocated identification signs acquired in 1970 and 1971 as follows:

+------------------------------------------+ ¦ ¦Year of acquisition ¦ +--------------------+---------------------¦ ¦Year of relocation ¦1970 ¦1971 ¦ +--------------------+----------+----------¦ ¦ ¦ ¦ ¦ +--------------------+----------+----------¦ ¦1976 ¦69 ¦68 ¦ +--------------------+----------+----------¦ ¦1977 ¦172 ¦122 ¦ +--------------------+----------+----------¦ ¦1978 ¦32 ¦38 ¦ +--------------------+----------+----------¦ ¦Total ¦273 ¦228 ¦ +------------------------------------------+ The relocations listed above consist of (1) the removal from a service station property directly for reinstallation and use at a different location, (2) removal from a service station property to storage for later reuse, and (3) removal from storage for reinstallation and use at a different location. Information of this type is not available from American's accounting records for years prior to 1976 because said accounting records were first coded and modified to provide such information commencing after December 31, 1975. Such information, however, is representative of the retirements and relocations of signs for years prior to 1976.

In the years 1976 through 1978, American relocated lighting facilities acquired in 1970 and 1971 as follows:

+------------------------------------------+ ¦ ¦Year of acquisition ¦ +--------------------+---------------------¦ ¦Year of relocation ¦1970 ¦1971 ¦ +--------------------+----------+----------¦ ¦ ¦ ¦ ¦ +--------------------+----------+----------¦ ¦1976 ¦11 ¦12 ¦ +--------------------+----------+----------¦ ¦1977 ¦15 ¦20 ¦ +--------------------+----------+----------¦ ¦1978 ¦8 ¦7 ¦ +--------------------+----------+----------¦ ¦Total ¦34 ¦39 ¦ +------------------------------------------+ The relocations listed above, which include both single lighting facilities and groups of lighting facilities, consist of (1) the removal from a service station property directly for reinstallation and use at a different location, (2) removal from a service station property to storage for later reuse, and (3) removal from storage for reinstallation and use at a different location. Information of this type is not available from American's accounting records for years prior to 1976 because said accounting records were first coded and modified to provide such information commencing after December 31, 1975. Such information, however, is representative of the retirements and relocations of lighting fixtures for years prior to 1976.

In American's Chicago marketing region, which encompasses the Chicago metropolitan area and surrounding areas in Illinois and includes urban, suburban, and rural stations, Corkill Electric Co., one of American's installation and maintenance contractors, serviced 1,132 American service station identification signs of the types involved in this proceeding. In American's Chicago marketing region, Corkill Electric Co. removed obsolete sign heads and installed new ones at 163 locations in 1975, 148 in 1976, 18 in 1977, 33 in 1978, and 45 in 1979. That same contractor replaced 288 old lighting fixtures (in most cases, there were two fixtures mounted on one pole) at 21 locations in 1975, with lights that were of newer technology and/or more current design, 54 at 8 locations in 1976, 78 at 10 locations in 1977, 144 at 17 locations in 1978, and 67 at 9 locations in 1979. That same contractor removed signs and/or lights (meaning only poles and fixtures) due to station closings at 14 locations in 1975, 30 locations in 1976, 18 locations in 1977, 39 locations in 1978, and 15 locations in 1979. Such signs, and in many cases the lights, were returned to the contractor's inventory for reuse at another location. That same contractor also relocated signs and/or lights (meaning only poles and fixtures) within service station sites 6 times in 1975, 7 times in 1976, 14 times in 1977, and 15 times in 1978.

American customarily maintained a supply of sign heads, sign poles, and lighting fixtures and poles either in its own warehouses or in warehouses or storage yards of its installation contractors. Such supply consisted in large part of sign heads, poles, and lights that were removed from one location and, after reconditioning, if necessary, held for use at a different location.

Since 1970, three large signs (56 feet or higher) have been installed, and only two have been “removed,” in the entire Chicago region, both removals occurring as the result of station abandonments. In each instance of removal, the base or foundation was left in place, “removal” meaning the removal of only the sign head and pole or pedestal.

The base or foundation of a sign or light of one oil company or produced by a given manufacturer will not normally align properly for use with the pole or pedestal of a sign or light of a different company. A device known as a transition plate must first be manufactured or machined by the contractor before such new or replacement pole can be installed on the old foundation. This problem arises in connection with special situations, such as military posts, where the fuel supply contract is awarded on the basis of competitive bidding and may run for a short period of time.

Identification signs were installed in the service stations served by American to attract the attention of motorists and other potential customers and to identify the station as owned by or affiliated with American or its affiliates and as selling the products of American or its affiliates. Lighting facilities served to attract customers, to provide illumination of the pumps, service islands, driveways, and other portions of the premises for safety purposes and to permit nighttime operations.

In the consolidated Federal income tax return as filed by petitioner and its subsidiaries for the taxable year 1971, no investment credits were claimed with respect to the investment of Maryland or Texas in service station identification signs or lighting facilities. In its petition herein, petitioner claimed investment tax credits for that taxable year with respect to such investment in the total amount of $239,842.64. The respondent contends that such credit is not available.

Issue 3. Service Station Identification Signs and Lighting Facilities Depreciation

Some of the facts relevant to this issue were found in the preceding section, and are incorporated herein as necessary.

In petitioner's consolidated Federal income tax returns for its taxable years 1970 and 1971, it utilized the straight line method to compute depreciation on the used signs and lights acquired by Maryland and Texas during such years, and it utilized the 150-percent declining balance method to compute depreciation on the new signs and lights acquired by such subsidiaries during those years. It utilized those methods because it did not, at the time, believe that all or any portion of such signs and lights were section 1245 property, which property would have been depreciable at more accelerated rates.

Petitioner claims in its petition that, for those signs and lights which are section 1245 property, such property is depreciable for the taxable years 1970 and 1971 at more accelerated rates than originally claimed (sum of the year's digits for new property, 150-percent declining balance for used). The Commissioner disagrees, contending that, even if some of the signs and lights are section 1245 property, petitioner cannot change its method of depreciating such assets without the Commissioner's consent, which has not been requested.

Issue 4. Minimum Tax on Tax-Preference Items

Petitioner's tax returns as filed for its taxable years 1970 and 1971 computed minimum tax on tax-preference items for those taxable years under sections 56 through 58 in the respective amounts of $9,505,435.69 and $11,974,639.40. In his statutory notice of deficiency, the Commissioner reduced such amounts, because of his adjustments to other items, to $7,906,847.90 and $9,288,913.25. Final calculation of the minimum tax is dependent on our disposition of the other issues herein. However, petitioner contends that the minimum tax is not an income tax, thus exempting it from the provisions of section 275 which disallow the deduction of Federal income taxes, but rather that it is an excise deductible as an ordinary and necessary business expense under section 162. The Commissioner disagrees, contending that such tax is a Federal income tax.

OPINION

Issue 1. Offshore Platforms Intangible Drilling and Development Costs

Petitioner seeks to deduct as IDC the “other” costs of constructing nine offshore drilling platforms, which costs it incurred during its taxable years 1970 and 1971. It did not deduct such costs as IDC on the returns filed for those taxable years, nor did it deduct such costs on any of its returns for its taxable years prior to those taxable years. Instead, such costs were capitalized when incurred and expensed over the useful lives of the platforms. Respondent denies that such “other” costs are IDC.

As a preliminary issue, respondent asserts that, given the fact that petitioner consistently capitalized the “other” costs of constructing offshore drilling platforms, petitioner's attempt to deduct these costs as IDC constituted a change in its method of accounting which change is, absent the consent of the Internal Revenue Service, impermissible. Sec. 446(e). In support of this proposition, respondent cites numerous cases that merely establish either that the change of accounting method rules is grounded in a need for consistency and a desire to eliminate taxpayer-instigated distortions of income ( Advertisers Exchange, Inc. v. Commissioner, 25 T.C. 1086 (1956), affd. 240 F.2d 958 (2d Cir. 1957)), or that the taxpayer may not change from an incorrect to a correct method of accounting without the consent of the Commissioner. Commissioner v. O. Liquidating Corp., 292 F.2d 225 (3d Cir. 1961), cert. denied 368 U.S. 898 (1961); Wright Contracting Co. v. Commissioner, 36 T.C. 620 (1961), affd. 316 F.2d 249 (5th Cir. 1963), cert. denied 375 U.S. 879 (1963); sec. 1.446-(1)(e)(2)(i), Income Tax Regs. Respondent also cites these cases: Witte v. Commissioner, 513 F.2d 391 (D.C. Cir. 1975); Poorbaugh v. United States, 423 F.2d 157 (3d Cir. 1970); Hackensack Water Co. v. United States, 173 Ct. Cl. 606, 352 F.2d 807 (1965); In re Sperling's Estate v. Commissioner, 341 F.2d 201 (2d Cir. 1965), cert. denied 382 U.S. 827 (1965); American Can Co. v. Commissioner, 317 F.2d 604 (2d Cir. 1963), cert. denied 375 U.S. 993 (1964); Broida, Stone & Thomas, Inc. v. United States, 204 F. Supp. 841 (N. W. Va. 1962), affd. per curiam 309 F.2d 486 (4th Cir. 1962). Respondent's attempt to utilize the holdings of these cases to support his theory herein falls far short of the mark.

Section 446(e) provides:

(e) REQUIREMENT RESPECTING CHANGE OF ACCOUNTING METHOD .—-Except as otherwise expressly provided in this chapter, a taxpayer who changes the method of accounting on the basis of which he regularly computes his income in keeping his books shall, before computing his taxable income under the new method, secure the consent of the Secretary or his delegate.

The pertinent regulations provide that the term “method of accounting” includes not only the overall method of accounting (such as the cash or accrual method) but also the accounting treatment of any item. Sec. 1.446-1(a)(1), Income Tax Regs. With regard to a change in accounting method, respondent relies on regulations section 1.446-1(e)(2):

(2) (i) Except as otherwise expressly provided in chapter 1 of the Code and the regulations thereunder, a taxpayer who changes the method of accounting employed in keeping his books shall, before computing his income upon such new method for purposes of taxation, secure the consent of the Commissioner. Consent must be secured whether or not such method is proper or is permitted under the Internal Revenue Code or the regulations thereunder.

(ii) ( a) A change in the method of accounting includes a change in the overall plan of accounting for gross income or deductions or a change in the treatment of any material item used in such overall plan. Although a method of accounting may exist under this definition without the necessity of a pattern of consistent treatment of an item, in most instances a method of accounting is not established for an item without such consistent treatment. A material item is any item which involves the proper time for the inclusion of the item in income or the taking of a deduction. Changes in method of accounting include a change from the cash receipts and disbursement method to an accrual method, or vice versa, a change involving the method or basis used in the valuation of inventories (see sections 471 and 472 and the regulations thereunder), a change from the cash or accrual method to a long-term contract method, or vice versa (see sec. 1.451-3), a change involving the adoption, use or discontinuance of any other specialized method of computing taxable income, such as the crop method, and a change where the Internal Revenue Code and regulations thereunder specifically require that the consent of the Commissioner must be obtained before adopting such a change.

( b) A change in method of accounting does not include correction of mathematical or posting errors, or errors in the computation of tax liability (such as errors in computation of the foreign tax credit, net operating loss, percentage depletion or investment credit). Also, a change in method of accounting does not include adjustment of any item of income or deduction which does not involve the proper time for the inclusion of the item of income or the taking of a deduction. For example, corrections of items that are deducted as interest or salary, but which are in fact payments of dividends, and of items that are deducted as business expenses, but which are in fact personal expenses, are not changes in method of accounting. In addition, a change in the method of accounting does not include an adjustment with respect to the addition to a reserve for bad debts or an adjustment in the useful life of a depreciable asset. Although such adjustments may involve the question of the proper time for the taking of a deduction, such items are traditionally corrected by adjustments in the current and future years. For the treatment of the adjustment of the addition to a bad debt reserve, see the regulations under section 166 of the Code; for the treatment of a change in the useful life of a depreciable asset, see the regulations under section 167 (b) of the Code. A change in the method of accounting also does not include a change in treatment resulting from a change in underlying facts. On the other hand, for example, a correction to require depreciation in lieu of a deduction for the cost of a class of depreciable assets which had been consistently treated as an expense in the year of purchase involves the question of the proper timing of an item, and is to be treated as a change in method of accounting. Respondent argues that petitioner's attempt to deduct (as IDC) payments which he has long capitalized is an attempt to change the treatment of a material item used in the overall plan of accounting for gross income or deductions without the consent of the Commissioner. Inasmuch as the intangibles deduction affects the timing of the deduction of such payments, respondent contends that a change affecting such deduction is embraced within the language of the above-recited portion of the regulations which says, “A material item is any item which involves the proper time for * * * the taking of a deduction.” He then seeks to buttress his argument by the multiple citations listed above wherein taxpayers were prevented from changing from a “wrong” accounting method to a “right” one. Therefore, says respondent, even if the “other” costs in controversy are IDC, petitioner cannot change from a wrong method of accounting to a right one. Respondent makes a good pitch, but we believe that, in this instance, he is simply playing in the wrong ballpark.

There are many reasons why respondent's section 446(e) argument cannot prevail here. First, we would note that the type of “change” petitioner here seeks is not the type of abuse at which section 446(e) was aimed. A perusal of the above-quoted portion of the regulations leads one to the conclusion that the changes for which one must have advance permission fall generally into two categories: (1) Changes from one general approach in recording for tax purposes a given factual occurrence to another general approach (cash to accrual, accrual to cash, cash or accrual to long-term contract method, switching to the crop method), and (2) decisions concerning whether payments are for capital items, which should be deducted ratably over the useful life of the asset, or for expense items, which may be currently deducted. The former category is not the type of issue with which we are here confronted, though it can arise in the IDC context. See Stradlings Buildings Materials, Inc. v. Commissioner, 76 T.C. 84 (1981); Pauley v. United States, an unreported case (S.D. Cal. 1963, 11 AFTR 2d 955, 63-1 USTC par. 9280); Rev. Rul. 71-252, 1971-1 C.B. 146; Rev. Rul. 71-579, 1971-2 C.B. 225; Rev. Rul. 80-71, 1980-1 C.B. 106. Respondent has not alleged that, assuming the “other” costs in issue are IDC, petitioner seeks to deduct them in the wrong taxable year. Likewise, the second type of accounting method issue which is the target of the regulations under section 446(e), i.e., whether a payment represents the cost of a capital asset as opposed to an expense item, is absolutely irrelevant in the IDC context. Intangible drilling and development costs are admittedly capital expenditures. However, section 263(c), by the authority of which one deducts IDC, is an explicit exception to the general rule against deducting capital items. Sec. 263(a). In this context, section 446(e) cuts its widest swath when, though neither capitalizing nor expensing an item is clearly wrong, the taxpayer has made a choice as to the categorization of such items which choice he then decides to unilaterally change. Southern Pacific Transportation Co. v. Commissioner, 75 T.C. 497, 685 (1980). Any such change is inherently a distortion of income, regardless of whether the initial choice was, in the posthoc judgment of some tribunal, correct. Having said all that, it is easy to see why the “change” before us should not, as a matter of policy, come within the teeth of section 446(e). There is no right or wrong in electing, under section 1.612-4, Income Tax Regs., to deduct IDC. The election, which, if exercised, will clearly produce a major distortion of income, is specifically provided by Congress. If the election is made, all IDC must be deducted. Petitioner's tardy assertion that the “other” costs in issue should have been deducted does not, assuming such costs are IDC, constitute a discretionary choice that such costs should be deducted. It is a discovery that petitioner failed to deduct costs which, under the accounting method it has chosen, had to be deducted.

In the latter sense, petitioner's position constitutes an attempt to remedy its failure to report similar items consistently under a fixed method of accounting. Such correction of internal inconsistencies does not constitute a change in accounting method. Beacon Publishing Co. v. Commissioner, 218 F.2d 697, 701, 702 (10th Cir. 1955); Potter v. Commissioner, 44 T.C. 159 (1965); Schuster's Express, Inc. v. Commissioner, 66 T.C. 588 (1976), affd. without published opinion 562 F.2d 39 (2d Cir. 1977). Moreover, where a mistake of law affected the computation of a deduction under an established method of accounting, the subsequent correction of that error was deemed “tantamount to a mathematical error.” North Carolina Granite Corp. v. Commissioner, 43 T.C. 149 (1964). The correction of such items does not constitute a change in method of accounting. Sec. 1.446-1(e)(2)(ii)( b), Income Tax Regs. The situation before us admits of a similar analysis.

The inquiry before us, in the first instance, concerns the character of the payments in issue, though our decision on that issue ricochets quickly into the timing issue. In reality, petitioner has no choice (after electing to deduct IDC) in determining whether to deduct the costs before us. In such cases, the strictures of section 446(e) do not apply. Thompson-King-Tate, Inc. v. United States, 296 F.2d 290 (6th Cir. 1961); Underhill v. Commissioner, 45 T.C. 489 (1966).

To close the circle, we lean toward a simple disposition of this issue. Section 446(e) begins with the words, “Except as otherwise provided in this chapter.” Except in the limited context of the “prepaid intangibles” issue (and mutations thereon), the treatment of IDC is otherwise provided for in section 263(c). Where a taxpayer is merely seeking a substantive recharacterization of certain costs as IDC, section 446(e) is inapplicable. We deem it important to note that we are dealing with a situation where petitioner's right to deduct in the years before us some IDC under section 263(c) has not been questioned by respondent and that only the right to deduct other such costs in those same years is involved. We do not mean to suggest that section 446(e) would necessarily be inapplicable in the situation where a taxpayer has previously capitalized all IDC and then seeks to deduct such costs under section 263(c) without respondent's consent.

Having disposed of this preliminary issue, we can now turn to the task of determining whether the “other” costs of constructing the nine offshore drilling platforms in issue are deductible as IDC under section 263(c).

The history of the intangibles deduction is a fascinating one. Such history has been explicated at length elsewhere ( Exxon Corp. v. United States, 212 Ct. Cl. 258, 547 F.2d 548, 553-555, 563-564 (1976) (herein the Exxon case); Standard Oil Co. (Indiana) v. Commissioner, 68 T.C. 325, 345 n. 9 (1977)), therefore, we will not here repeat such history in detail. Suffice it to say that the option to deduct IDC arose administratively, was questioned in the courts, and finally received full legal status in section 263(c). It is, however, interesting to note the wording of those first regulations:

The incidental expenses of drilling wells, that is, such expenses as are paid for wages, fuel, repairs, etc., which do not necessarily enter into and form a part of the capital invested or property account, may, at the option of the individual or corporation owning and operating the property, be charged to property account subject to depreciation or be deducted from gross income as an operating expense. [T.D. 2447 (unpublished), relating to the Revenue Act of 1916.] A restatement of these regulations (as well as of intervening amendments and additions thereto) was promulgated in 1932 with this prologue, “no change in administrative policy or in practice under the regulations is made, or intended to be made, by this restatement.” T.D. 4333, XI-1 C.B. 31 (1932). The pertinent portions of the restated regulations are practically identical to the pertinent portions of the regulations with which we are here concerned. Section 1.612-4, Income Tax Regs., which is conceded to contain the controlling criteria by which we are to decide the issue before us, provides, as here relevant:

Sec. 1.612-4. Charges to capital and to expense in case of oil and gas wells.

(a) Option with respect to intangible drilling and development costs. In accordance with the provisions of section 263(c), intangible drilling and development costs incurred by an operator (one who holds a working or operating interest in any tract or parcel of land either as a fee owner or under a lease or any other form of contract granting working or operating rights) in the development of oil and gas properties may at his option be chargeable to capital or to expense. This option applies to all expenditures 385 made by an operator for wages, fuel, repairs, hauling, supplies, etc., incident to and necessary for the drilling of wells and the preparation of wells for the production of oil or gas. Such expenditures have for convenience been termed intangible drilling and development costs. They include the cost to operators of any drilling or development work (excluding amounts payable only out of production or gross or net proceeds from production, if such amounts are depletable income to the recipient, and amounts properly allocable to cost of depreciable property) done for them by contractors under any form of contract, including turnkey contracts. Examples of items to which this option applies are, all amounts paid for labor, fuel, repairs, hauling, and supplies, or any of them, which are used

(1) In the drilling, shooting, and cleaning of wells,

(2) In such clearing of ground, draining, road making, surveying, and geological works as are necessary in preparation for the drilling of wells, and

(3) In the construction of such derricks, tanks, pipelines, and other physical structures as are necessary for the drilling of wells and the preparation of wells for the production of oil or gas.

In general, this option applies only to expenditures for those drilling and developing items which in themselves do not have a salvage value. For the purpose of this option, labor, fuel, repairs, hauling, supplies, etc., are not considered as having a salvage value, even though used in connection with the installation of physical property which has a salvage value. Included in this option are all costs of drilling and development undertaken (directly or through a contract) by an operator of an oil and gas property whether incurred by him prior or subsequent to the formal grant or assignment to him of operating rights (a leasehold interest, or other form of operating rights, or working interest); except that in any case where any drilling or development project is undertaken for the grant or assignment of a fraction of the operating rights, only that part of the costs thereof which is attributable to such fractional interest is within this option. In the excepted cases, costs of the project undertaken, including depreciable equipment furnished, to the extent allocable to fractions of the operating rights held by others, must be capitalized as the depletable capital cost of the fractional interest thus acquired.

(b) Recovery of optional items, if capitalized. (1) Items returnable through depletion: If the taxpayer charges such expenditures as fall within the option to capital account, the amounts so capitalized and not deducted as a loss are returnable through depletion insofar as they are not represented by physical property. For the purposes of this section the expenditures for clearing ground, draining, road making, surveying, geological work, excavation, grading, and the drilling, shooting, and cleaning of wells, are considered not to be represented by physical property, and when charged to capital account are returnable through depletion.

(2) Items returnable through depreciation: If the taxpayer charges such expenditures as fall within the option to capital account, the amounts so capitalized and not deducted as a loss are returnable through depreciation insofar as they are represented by physical property. Such expenditures are amounts paid for wages, fuel, repairs, hauling, supplies, etc., used in the installation of casing and equipment and in the construction on the property of derricks and other physical structures.

(3) In the case of capitalized intangible drilling and development costs incurred under a contract, such costs shall be allocated between the foregoing classes of items specified in subparagraphs (1) and (2) for the purpose of determining the depletion and depreciation allowances.

(4) Option with respect to cost of nonproductive wells: If the operator has elected to capitalize intangible drilling and development costs, then an additional option is accorded with respect to intangible drilling and development costs incurred in drilling a nonproductive well. Such costs incurred in drilling a nonproductive well may be deducted by the taxpayer as an ordinary loss provided a proper election is made in the return for the first taxable year beginning after December 31, 1942, in which such a nonproductive well is completed. Such election with respect to intangible drilling and development costs of nonproductive wells is a new election, and, when made, shall be binding for all subsequent years. Any taxpayer who incurs optional drilling and development costs in drilling a nonproductive well must make a clear statement of election under this option in the return for the first taxable year beginning after December 31, 1942, in which such nonproductive well is completed. The absence of a clear indication in such return of an election to deduct as ordinary losses intangible drilling and development costs of nonproductive wells shall be deemed to be an election to recover such costs through depletion to the extent that they are not represented by physical property, and through depreciation to the extent that they are represented by physical property.

(c) Nonoptional items distinguished. (1) Capital items: The option with respect to intangible drilling and development costs does not apply to expenditures by which the taxpayer acquires tangible property ordinarily considered as having a salvage value. Examples of such items are the costs of the actual materials in those structures which are constructed in the wells and on the property, and the cost of drilling tools, pipe, casing, tubing, tanks, engines, boilers, machines, etc. The option does not apply to any expenditure for wages, fuel, repairs, hauling, supplies, etc., in connection with equipment, facilities, or structures, not incident to or necessary for the drilling of wells, such as structures for storing or treating oil or gas. These are capital items and are returnable through depreciation.

(2) Expense items: Expenditures which must be charged off as expense, regardless of the option provided by this section, are those for labor, fuel, repairs, hauling, supplies, etc., in connection with the operation of the wells and of other facilities on the property for the production of oil and gas. Respondent urges us to abjure our former position and to construe these provisions narrowly, citing Deputy v. du Pont, 308 U.S. 488 (1940), and New Colonial Ice Co. v. Helvering, 292 U.S. 435 (1934). However, a more appropriate constructional maxim in this context is that, “Congress favors a liberal interpretation of the regulation.” Gates Rubber Co. v. Commissioner, 74 T.C. 1456, 1475 (1980); Sun Co. v. Commissioner, 74 T.C. 1481, 1508 (1980); Standard Oil Co. (Indiana) v. Commissioner, 68 T.C. at 345; Exxon Corp. v. United States, 547 F.2d at 555. We agree with the Court of Claims that the courts should not be niggardly in their approach to these regulations, inasmuch as the IDC option is viewed by Congress as an incentive to oil and gas prospecting and exploration, a continuing objective of national importance. Exxon Corp. v. United States, 547 F.2d at 555.

The issue herein is a new one for this Court, but it has been considered, discussed, and decided by the Court of Claims. In the Exxon case, the issue was resolved favorably to the taxpayer. A reading of the several opinions in that case provides an excellent exposition of the conflicting theories which can control the resolution of this issue.

The platforms involved in the Exxon case were templet-type, as opposed to jacket-type, platforms. Templet-type platforms were described by the Court of Claims as having “a large deck area, on which are mounted derricks and various other drilling paraphernalia, all supported above sea level by ‘templets,’ which are compound, trussed structures, analogous in function to table legs but composed of several large vertical steel beams and pipes (usually an even number) arranged in a rectangular fashion with bars running between the pipes for support and spacing. Several templets are ordinarily used to support one deck, the number depending on the size, weight, and other features of the deck and equipment to be installed thereon.” Exxon Corp. v. United States, 547 F.2d at 549-550 n. 4. It appears that the judges on the court agreed that the basic component, the templet, was standard for all platforms. Exxon Corp. v. United States, 547 F.2d at 551, 562. The templets were clearly designed to be salvaged as a unit and were reusable.

Faced with these facts, the majority threaded its way through the controlling regulations and held that all of the onshore costs of fabricating offshore platforms, including the costs of fabricating the salvageable templets, were IDC. It quickly drew the line between “actual materials” and other costs in such a fashion that the Government's argument, that salvageable components are “actual materials,” was definitionally destroyed at the outset. Then, it moved on to address the “salvage value” issue.

The regulations provide that the IDC option “applies only to expenditures for those drilling and development items which in themselves do not have a salvage value.” Sec. 1.612-4(a), Income Tax Regs. (Emphasis added.) The majority paraphrased this requirement throughout its opinion by reciting the above statement as requiring that such expenditures “must not in and of themselves ‘have a salvage value’.” Exxon Corp. v. United States, 547 F.2d at 556. (Emphasis added.) Such an approach resulted in a decision by the court that, because the various costs of labor, fuel, etc., in constructing a platform do not, when each is considered individually (“in and of itself”), have salvage value, and because the term “actual materials” was defined as the materials purchased by the operator (or the contractor) from which the platform and the major component parts thereof were constructed (no consideration being given to the fact that a salvageable major component, like a templet, could be viewed as an “actual material”), the costs of fabricating such platforms were IDC. The remainder of the majority opinion fends off various arguments by the Government, all of which were doomed to failure by this interpretation of the terms “actual materials” and “items which in themselves do not have a salvage value.”

Judge Davis, in his concurring opinion, crystallized the majority's approach. He was impressed with the all-embracing theme of the opening line of the regulation, and would relegate the “salvage value” concepts to a subordinate role. He perceives that all expenditures made by an operator for wages, fuel, etc., incident to and necessary for the drilling of wells and the preparation of wells for production are IDC, and that the references to salvage value merely show the characteristic of tangible “actual materials” and do not operate to take expenditures out of the option that would have been within the option had they not been used to fabricate a component which itself ordinarily has salvage value. Again, the dominant theme is that “actual materials” are physical and tangible materials which are transformed via labor, fuel, etc., into the desired drilling asset. We are repeatedly told that actual materials are actual materials, and the Government's theory that a salvageable templet is an actual material is dismissed out of hand.

Judge Bennett, in his concurring opinion, agrees substantively with both the majority opinion and with Judge Davis' concurring opinion, and he further emphasizes the savings in judicial effort inherent in the approach of the majority. He laments the possibility that, were the Government's theory adopted, “it would become necessary to determine exactly what components of the final assembly could be saved as they are and subsequently reused.” Exxon Corp. v. United States, 547 F.2d at 560. Noting that such determinations would be difficult and time consuming, he concludes that the ease of administration inherent in the majority's approach is an additional reason why he concurs in the majority's holding.

Judge Kashiwa, on the other hand, believes that the templets (and other items which were fabricated onshore and had salvage value) are included within the meaning of the words “actual materials,” and that the expenditure for wages, fuel, etc., for constructing such templets are “expenditures by which the taxpayer acquires tangible property ordinarily considered as having a salvage value,” which expenditures do not come within the option to deduct IDC. Sec. 1.612-4(c)(1), Income Tax Regs. The following passage is the heart of the analysis in Judge Kashiwa's opinion:

Since the templets were designed to be salvaged as a component part in unit form, they ordinarily would be considered as having a salvage value without regard to the frequency of actual salvage or the actual reasons therefor. Nevertheless, as the trial judge found, “after considerable modification and reconditioning, most of the salvaged parts of [the platform] * * * were reusable at least once in other platforms.” The extent of modification to which the trial judge refers is the joining together of several 10' x 10' templets in order to form a 10' x 20' templet, or the adding of extensions to the basic templet unit. The basic unit design of the templet was never altered. As a result, the labor, fuel and supplies utilized to fabricate the lengths of pipe and steel beams into a templet were permanently integrated into the templet, and thereby had salvage value.

After having carefully read the trial judge's recommended decision and before entering into further discussion, I note the focal emphasis in the trial judge's opinion is not on the basic templet component unit as above described but, rather, is on the tangible basic materials which make up the templet unit. In my opinion, the trial judge incorrectly assumes that the intangible basic materials (labor, fuel and supplies) utilized to fabricate the tangible basic materials (steel beams and pipes) into a templet unit do not have a salvage value. I view the costs attributable to labor, fuel and supplies, etc., incurred by the taxpayer in fabricating the basic templet unit as expenditures by which the taxpayer acquired “tangible property [the templet unit] ordinarily considered as having a salvage value.” Reg. 118, sec. 39.23(m)-16(c)(1). Therefore, those expenditures are nonoptional items. [ Exxon Corp. v. United States, 547 F.2d at 562-563; fn. refs. omitted.] After a skillful analysis of the history of the IDC option, which analysis tilts the scales slightly in favor of the interpretation for which he contends, Judge Kashiwa summarizes thusly:

The labor, fuel, etc., used in erecting the platform structure, or in transporting the structure to the drilling site, add no value to the structure which can be salvaged when the drilling operation is completed and, hence, do not “in themselves” have salvage value. On the other hand, labor, fuel, etc., used in fabricating the salvageable components of such a structure do add value to and become integrated with the tangible basic materials comprising the component part. Therefore, the items, both intangible and tangible materials, have salvage value “in themselves.” Having a salvage value “in themselves,” the items do not qualify for the IDC option; the cost of the items must be capitalized and recovered only through depreciation. In other words, the general rule as stated in Section 263(a) of the Internal Revenue Code of 1954 is applicable, not the exception to the general rule, i.e., Section 263(c). [ Exxon Corp. v. United States, 547 F.2d at 565-566.]

It is apparent that the authors of these various opinions have set forth therein the major arguments for and against the deduction of petitioner's “other” costs. The parties herein have improved little upon the arguments presented to and discussed by the Court of Claims in the Exxon case.

Respondent leads with a couple of weak punches. He first spuriously contends that petitioner's return treatment of the costs in issue constitutes an admission that they are not IDC and that such “admission” increases petitioner's burden herein. It is not and it does not.

He next proffers this argument: in order to meet the regulations' requirement that the expenditures made be “incident to and necessary for the drilling of wells and the preparation of wells for the production of oil or gas,” the expenditures must be “incurred during and entirely committed to drilling or development.” It seems to bother respondent that successful drilling platforms actually spend most of their useful lives producing, as opposed to drilling for, oil and gas. Respondent's position herein is not only wrong, premised as it is on a tortured rephrasing of the regulations, but is also contrary to his own published position. In Revenue Ruling 70-596, 1970-2 C.B. 69, the Commissioner states that, “The offshore platform * * * is incident to and necessary for the drilling of wells, even though it is useful in connection with subsequent production activities.” It cannot seriously be disputed that offshore drilling platforms are incident to and necessary for the drilling of wells.

Respondent finally homes in on his serious argument, which is, in essence, the same argument rejected by the majority of the Court of Claims in the Exxon case. He contends that the entire cost of constructing the platforms here in issue constitutes expenditures to acquire tangible property ordinarily considered as having a salvage value, which expenditures do not come within the option to deduct IDC. Sec. 1.612-4(c)(1), Income Tax Regs. He categorizes the fabricated deck, jacket, and pilings as “actual materials” because, in respondent's estimation, such components are salvageable. A telling point is made when he inquires how to distinguish, under the Court of Claims' majority analysis, between the costs of fabricating angle iron (“actual material” in the judgment of the majority of the Court of Claims) into a major component like a jacket and the costs of turning iron ore (arguably “actual material”) into angle iron. An approach that will deem the former IDC and deny such characterization to the latter must find some way to distinguish between the two processes. It is admitted that it is irrelevant whether an operator fabricates his own platforms or contracts that job out. A solution to this quandary must be reached, says respondent.

Of course, respondent contends that, should we adopt his reasoning, petitioner has failed to prove that the platforms were not salvageable. He further argues that, should we adopt the Court of Claims' approach, petitioner has failed to carry his burden of allocating costs between materials and “other” costs, with specific attention being given to various items which respondent claims were “production” items.

Petitioner takes the most favorable portions of the various opinions in the Exxon case and molds them into a broad argument in favor of classifying the expenditures here in issue as IDC. Taking a cue from Judge Davis' concurring opinion, petitioner begins with the assertion that the opening sentence of the applicable regulations provides for the option to deduct all IDC, which include all wages, fuel, repairs, hauling, supplies, etc., incident to and necessary for the drilling of wells and the preparation of wells for the production of oil and gas. It basically tracks the reasoning of the majority opinion of the Court of Claims in contending that it is irrelevant whether the platforms in issue do or do not have salvage value. It would define as “actual materials” only those items purchased by the fabricator of the platforms, whether that be the operator or an independent contractor. Pointing to the inclusion in the regulations of “tanks” in both the items that are subject to the option, sec. 1.612-4(a), Income Tax Regs., and the items that are not, sec. 1.612-4(c)(1), Income Tax Regs., petitioner asserts that the only meaningful distinction between the two is that items that are constructed by the operator or his contractor are subject to the option, while items that are purchased by such operator or his contractor are not.

Citing all these arguments, plus the argument for judicial economy made by Judge Bennett in the Exxon case, petitioner concludes that we should adopt the broad holding of the Court of Claims and decide this case in its favor. Moreover, argues petitioner, if salvage value is an issue, i.e., if we adopt Judge Kashiwa's rationale, petitioner's nine jacket-type platforms are not salvageable. Petitioner further disputes respondent's claim that petitioner has failed to carry its burden of proving the allocation of expenditures between various categories of costs.

Both parties haggle over the import of this phrase of the regulations:

In general, this option applies only to expenditures for those drilling and developing items which in themselves do not have a salvage value. For the purpose of this option, labor, fuel, repairs, hauling, supplies, etc., are not considered as having a salvage value, even though used in connection with the installation of physical property which has a salvage value. * * * [Sec. 1.612-4(a), Income Tax Regs.] Petitioner argues that “installation” cannot be distinguished from off-site construction and, therefore, that this phrase extends to the costs here in issue. Respondent concludes that the reference to installation is exclusive and, as a result, that labor, fuel, etc., costs incurred in the construction phase are, by force of this sentence of the regulations, absolutely excluded from the IDC option. The majority in the Exxon case rejected respondent's interpretation and skated perilously close to adopting petitioner's:

In seizing upon this isolated word “installation” as controlling the entire operation of the regulation, defendant has grossly misread its own language. The obvious reason for the clause in question is to eliminate a possible contention that the option-type expenditures (labor, fuel, etc.) acquire a salvage value simply because they were connected with the installation of admittedly salvable property. Thus, as plaintiff correctly observes, the clause in no way restricts the application of the regulation but instead expands it to include a situation where option-type expenditures can be related to salvable property without losing their own characterization as nonsalvable items. [ Exxon Corp. v. United States, 547 F.2d at 556.]

However, we agree with Judge Kashiwa that the sentence in question “expands” the coverage of the IDC regulations only insofar as it assures that the immediately preceding sentence therein is not to be interpreted to exclude from the option installation costs incurred with respect to salvageable property. Exxon Corp. v. United States, 547 F.2d at 563.

“In general, this option applies only to expenditures for those drilling and development items which in themselves do not have a salvage value.” Sec. 1.612-4(a), Income Tax Regs.
6. Marineland of the Pacific, Inc. v. Commissioner, T.C. Memo. 1975-288.

With these various theories, rationales, and explanations before us, we must now chart the path that we think appropriate through the interstices of the law of the intangibles deduction. We perceive a great need for synthesis, and we will herein attempt to state a broad rationale from which we can make the requisite detailed holding.

Our analysis must begin and end with the wording of the controlling regulations, section 1.612-4, Income Tax Regs. Faced with the task of classifying certain costs as IDC or not IDC, we can isolate several portions of such regulations that provide guidance.

First, there is the second sentence of the regulation, which sentence broadly enunciates the general characteristics of IDC:

This option applies to all expenditures made by an operator for wages, fuel, repairs, hauling, supplies, etc., incident to and necessary for the drilling of wells and the preparation of wells for the production of oil or gas. [Sec. 1.612-4(a), Income Tax Regs.] We have previously disposed of respondent's contention that the expenditures in issue were not incident to and necessary for the drilling of wells and the preparation of wells for the production of oil or gas. Furthermore, there is no question but that the expenditures were made by the operator of the subject properties and that petitioner, as an owner of some or all of the operating interests in the relevant properties, is entitled to deduct its allocable share of IDC. Thus, the quoted sentence is germane in our search for the parameters of the IDC option only insofar as it announces the general nature of the expenditures which will be subject to the IDC option, i.e., “wages, fuel, repairs, hauling, supplies, etc.,” which we will herein refer to as “intangible-type costs.”

The two sentences following the above-discussed sentence add nothing to the definition of IDC, save for the fact that the second sentence eliminates any contention that costs paid or incurred for drilling or development work done by a contractor, which costs would qualify as IDC if done by the operator, are not IDC.

The next pertinent portion of the regulation in our quest to discern the nature of the IDC is the following:

Examples of items to which this option applies are, all amounts paid for labor, fuel, repairs, hauling, and supplies, or any of them, which are used

(1) In the drilling, shooting, and cleaning of wells,

(2) In such clearing of ground, draining, road making, surveying, and geological works as are necessary in preparation for the drilling of wells, and

(3) In the construction of such derricks, tanks, pipelines, and other physical structures as are necessary for the drilling of wells and the preparation of wells for the production of oil or gas.

In general, this option applies only to expenditures for those drilling and developing items which in themselves do not have a salvage value. For the purpose of this option, labor, fuel, repairs, hauling, supplies, etc., are not considered as having a salvage value, even though used in connection with the installation of physical property which has a salvage value. * * * [1.612-4(a), Income Tax Regs.] The first sentence reiterates the type of expenditures that will be subject to the option, i.e., intangible-type costs, and further lists the kind of activities in which such expenditures must be incurred in order to qualify as “drilling and development costs.” It is clear that offshore drilling platforms are physical structures that are necessary for the drilling of wells and the preparation of wells for the production of oil or gas. Having decided that drilling platforms are so necessary, it is apparent to us that the “other” costs in issue, which are intangible-type costs, meet the requirements of this sentence.

However, the next sentence in the above-quoted phrase provides the first applicable paring back of the expenditures that, up to that point in the regulation, would qualify as IDC. It states that the option applies only to expenditures for those drilling and development items which in themselves do not have a salvage value. Next follows the statement that intangible-type costs are not considered as having a salvage value even though used in connection with installing tangible property which has a salvage value. These sentences provide the fertile ground upon which the parties herein have sown their first seeds of discord.

There are few remaining interpretative aids within these regulations. Subsection (b) reveals only that there may be expenditures within the option that are “represented by physical property.” Thus, the mere fact that the “other” costs here in issue are represented by physical property, such as the jacket, deck, and pilings, does not, per force of section 1.612-4(b), Income Tax Regs., either qualify or disqualify such costs as IDC.

Finally, there is the critical subsection (c)(1), which provides (for our purposes):

(c) Nonoptional items distinguished. (1) Capital items: The option with respect to intangible drilling and development costs does not apply to expenditures by which the taxpayer acquires tangible property ordinarily considered as having a salvage value. Examples of such items are the costs of the actual materials in those structures which are constructed in the wells and on the property, and the cost of drilling tools, pipe, casing, tubing, tanks, engines, boilers, machines, etc. * * * The remainder of that subsection deals either with expenditures for nondrilling activities or with current operators' expenditures made during the production stage of a well. The above-quoted sentences, which provide that expenditures by which a taxpayer “acquires tangible property ordinarily considered as having a salvage value” are not within the option and which further provide examples of such expenditures, must be set next to the sentences from subsection (a) regarding “items which in themselves do not have a salvage value” in order to resolve the issue before us. The language from subsection (c) definitely carves certain expenditures out of the IDC option. We are here asked to determine how extensive this exclusion is.

Petitioner would synthesize these two predominant IDC-characterizing phrases (the two sentences in subsection (a) which are discussed supra at 393-394, and the first two sentences of subsection (c)(1)) by saying that those “actual materials” purchased by the operator (or indirectly by him under any form of contract relating to the construction of the platform) are nonoption items, whereas any work performed by such operator (or indirectly by him under any form of contract relating to the construction of the platform) in order to utilize such materials and construct the platform would qualify as IDC. Therefore, says petitioner, the salvage value, or lack thereof, of the platform itself is irrelevant. This is, in essence, the approach of the majority of the Court of Claims. It is, however, too riddled with conceptual flaws for us to accept.

Respondent points out that petitioner's approach fails to deal with the fact that these “purchased” materials themselves have intangible-type costs bound up within them. A purchased engine, which petitioner would call an “actual material” because it is purchased, is the product of another “contractor” who purchased “actual materials” and expended intangible-type costs to perform work in order to manufacture a finished product. Everyone admits that IDC do not lose their character as such merely because they are expended indirectly through contractors. This analysis can extend backward and forward and shows the poverty of petitioner's “salvage-value-is-irrelevant” argument. Until one reaches the natural raw materials found in the soil (and maybe beyond, if one assumes that the Creator performed intangible-type services to produce Mother Earth), each level of production is the result of the expenditure of intangible-type costs which, ultimately, are expended for drilling and development. Clearly we must draw a line. Thus, the salvage value concept.

The regulation says that IDC generally do not “in themselves” have salvage value, and that expenditures to acquire tangible property ordinarily considered as having a salvage value are not IDC. The former statement yields little help, appearing merely to be a statement that intangible-type costs do not have salvage value “in themselves.” However, the latter guidepost, especially if viewed as explanatory of the former statement, is truly helpful in our search for the outer limits of the IDC option. In excluding from the option expenditures for ordinarily salvageable tangible property, the Treasury, and now Congress, appears to have drawn the line such that expenditures that ordinarily are economically unrecoverable should the well be dry, whether or not such expenditures are “represented by physical property,” are to be included within the option, whereas expenditures for items which ordinarily are recoverable, even if the well is dry, are excluded from such option. Courts have long recognized that the allowability of the deduction of IDC goes hand-in-hand with the taking of risks:

The argumentative justification for liberality in taxation of oil and gas is that such liberality encourages and emboldens the fiscally timid to exploit the hidden resource. It rewards the risk-taker. * * * [ United States v. Cocke, 399 F.2d 433, 452 (5th Cir. 1968).]

The regulations do not contemplate that investors * * * [can be] allowed a deduction for intangible drilling costs without assuming the risk of the unknown result of the drilling. * * * [ Haass v. Commissioner, 55 T.C. 43, 50 (1970).]

Thus, it is clear that risk and IDC are inextricably related. [ Standard Oil Co. (Indiana) v. Commissioner, 68 T.C. at 350.]

The taking of risks has always been inextricably related to the availability of the IDC option. [ Gates Rubber Co. v. Commissioner, 74 T.C. at 1477; Sun Co. v. Commissioner, 74 T.C. at 1510.] Thus, we see the relevance of the phrase “ordinarily considered as having a salvage value.” If an item ordinarily has salvage value, expenditures for that item are not subject to the risks of the drilling activity. If it does not, then expenditures for such an item (or, in the purest case, where the expenditure is not represented by an item) will be absolutely unrecoverable should the well be dry.

It is at this point that we must come to grips with the language and holding of Harper Oil Co. v. United States, 425 F.2d 1335 (10th Cir. 1970), vacating and remanding an unreported District Court case. In that case, the taxpayer sought to deduct the cost of surface casing, which is an outer casing of steel pipe used to prevent cave-ins and to prevent contamination of fresh water strata which have been penetrated. Under Oklahoma law (the subject wells were drilled in Oklahoma), surface casing was required to be cemented into the wellbore when fresh water strata were encountered. Thus, the surface casing was not salvageable. Though “casing” is listed as an example of “tangible property ordinarily considered as having a salvage value,” the taxpayer, reasoning that the cost of such casing was at risk regardless of the productivity of the wells, i.e., that the casing was not “salvageable,” deducted such cost as IDC. Justice Blackmun, who was, at the time, a judge of the U.S. Court of Appeals for the Eighth Circuit, sitting by designation on a Tenth Circuit panel, authored the opinion in which the Tenth Circuit determined that such costs were not within the IDC option. The following presents the court's rationale for that decision:

7. The salvage value reference strikes us only as the usual, but not the necessary, characteristic of the non-option item. We do not regard salvage value as a condition of non-option status. The successive regulations have consistently referred to “tangible property ordinarily considered as having a salvage value.” See, for example, Treas. Reg. sec. 1.612-4(c)(1). Certainly, casing of all kinds ordinarily would be considered as having a salvage value. Harper's surface-casing used in Oklahoma in the presence of fresh water strata has no salvage value primarily because the Oklahoma regulations require cementing and prohibit removal. Otherwise there is no real argument that surface-casing, as such, “ordinarily” would not have a salvage value. Again Mertens refers to the practicalities. “Some of the casing and other equipment may be salvaged, but a considerable portion of it is likely to be lost in any event,” and, “Casing used in a particular well can usually be salvaged in part, at least.” 4 Mertens Law of Federal Income Taxation sec. 24.47 pp. 255-256.

8. There is no dispute that the costs of the components of the production string are not subject to the option. Yet, as we have noted, a part of the string often is cemented and thus made irremovable. But then the absence of salvage value does not qualify the cost of the cemented part of the string as expensable. Thus salvage value does not always attend a non-option cost. There is no more reason to say that the absence of salvage value qualifies a cost for the option.

9. We feel that the District Court too narrowly construed the term “ordinarily” in the governing regulation. It reasoned that because surface-casing in Oklahoma rarely, if ever, can be removed, it “ordinarily” could have no salvage value. We relate “ordinarily” to casing in general and not to Oklahoma surface-casing in particular. Casing is casing. And casing “ordinarily” has salvage value. [ Harper Oil Co. v. United States, supra at 1342-1343.] Portions of that quote would seem to imply that salvage value need not always attend nonoption status. However, it appears that Justice Blackmun was saying that, although surface casing which is used in an extraordinary manner may not have salvage value, such a phenomenon does not affect the ordinary classification of casing as an item that ordinarily does have a salvage value. Thus, lack of salvage value, because of a particular use, does not necessarily qualify a cost as IDC. Therefore, since “casing of all kinds ordinarily would be considered as having a salvage value * * * the absence of salvage value [in an extraordinary circumstance] does not qualify the * * * cemented part of the string as expensable. * * * We relate ‘ordinarily’ to casing in general.” Harper Oil Co. v. United States, supra at 1343 (bracketed language added). Justice Blackmun took note of the opinion of an authority who stated that usually surface casing is cemented (thus rendering it nonsalvageable) only in the completion of a producing well. Harper Oil Co. v. United States, supra at 1342. Under a risk analysis, Justice Blackmun, relying on such statement, could easily conclude that casing is not cemented until and unless oil or gas was discovered in commercially producible quantities and, therefore, is not at risk such that the costs of such casing should qualify for the IDC option. Both parties rely on the case to prove different points, but we find it easy to integrate the language and the holding of Harper Oil into our risk analysis, especially in light of the teaching of such case that the salvageability of the item in question should be determined with an eye toward the ordinary manner in which it is used.

This rationale is, in slightly different form, functionally the same analysis proffered by Judge Kashiwa in the Exxon case. Inasmuch as every judge seemed to agree that the templets were designed to be, and in fact were, salvageable, Judge Kashiwa believed that the intangible-type costs incurred to construct such templets were part of the cost of acquiring tangible property which is ordinarily considered as having a salvage value. It is hard to fault his logic. Given the same factual finding, we would, under our risk analysis, reach a similar conclusion. However, if we were to find as a fact that such an item was not ordinarily considered as having a salvage value, we would be forced to determine what, if any, of the costs of building such an item are expenditures to acquire tangible property which is ordinarily considered as having a salvage value. Using our risk analysis to interpolate this salvage value parameter, we would make that decision based upon this formula: when the ultimate tangible property resulting from a chain of drilling, development, construction, etc., activities (such activities being of the type covered by the IDC option) is ordinarily considered as having a salvage value, none of the costs of acquiring or constructing such property are IDC. If such ultimate tangible property is not ordinarily considered as having a salvage value, then the intangible-type costs expended to integrate materials which were, prior to such integration, usable in such a fashion that they would be ordinarily considered as having a salvage value, into a component which is, after such integration, not ordinarily considered as having a salvage value, are IDC. Any further intangible-type costs expended to integrate this “first unsalvageable component” into the ultimate tangible property, which is not ordinarily considered as having a salvage value, are IDC.

Thus, the costs of turning iron ore into salvageable angle iron are not IDC, and the costs of turning angle iron into a salvageable templet would not be IDC. However, the costs of turning sheet metal, which up until that point is usable in such a fashion that it would be ordinarily considered as having a salvage value, i.e., it could still be utilized in an ultimately salvageable asset, into an unsalvageable piling (assuming that such piling is not ordinarily considered as having a salvage value) would, assuming the platform is unsalvageable, qualify as IDC.

One can see that, assuming that certain types of platforms are not ordinarily considered as having a salvage value, this test resembles an “actual materials” (as that term is used by petitioner) versus intangible-type costs dichotomy, without relying, however, on the semantically puzzling term “actual materials.”

Of course, this kind of analysis is the prime target of the criticism leveled by Judge Bennett in his Exxon case concurrence. He deplored as unworkable any analysis that would produce a situation where “it would become necessary to determine exactly what components of the final assembly could be saved as they are and subsequently reused.” Exxon Corp. v. United States, 547 F.2d at 560. We also cringe at the thought of making such determinations. However, such determinations are necessary because the principle undergirding the IDC option is risk. If components are ordinarily salvageable, they are not risked, and the costs of their construction or acquisition do not qualify for the IDC option.

Therefore, in order to decide the issue before us, we must decide: (1) Whether the platforms as a whole are ordinarily considered as having a salvage value; and (2) if the answer to (1) is no, whether the intangible-type costs in issue were expended to integrate materials which were, prior to such integration, usable in such a fashion that they would be ordinarily considered as having a salvage value, into components which are, after such integration, not ordinarily considered as having a salvage value.

Are jacket-type platforms of the type in issue ordinarily considered as having a salvage value? Clearly not. There is no evidence that any platforms have ever been salvaged or reused in their entirety at the end of their normal 10- to 15-year useful lives. A marine contractor, J. Ray McDermott & Co., Inc., does not allow any salvage or scrap value to offset the cost it quotes for removing platforms. Conoco has found that the least expensive procedure for removing platforms is to have such contractors dispose of them, dumping them in approved dumping locations. Drilling platforms, the ultimate tangible property here involved, are not ordinarily considered as having a salvage value.

Are the “other” costs which are here in issue intangible-type costs which were expended to integrate materials which were, prior to such integration, usable in such a fashion that they would be ordinarily considered as having a salvage value, into components which are, after such integration, not ordinarily considered as having a salvage value? We find that they were.

First, the parties stipulated that the costs in issue were for “labor, fuel, repairs, hauling, supplies, etc. (and an allocable portion of overhead or profit).” These costs fit the general description of intangible-type costs found in the second and fifth sentences of section 1.612-4(a), Income Tax Regs. Second, neither party contends that any of the costs it has deemed “material” costs were for items which are not ordinarily considered as having a salvage value. Because petitioner bears the burden of proof as to all factual determinations herein ( Welch v. Helvering, 290 U.S. 111 (1933); Rule 142(a), Tax Court Rules of Practice and Procedure), we find that all of the costs for “material” were expenditures to acquire tangible property ordinarily considered as having a salvage value.

Finally, we approach the question of whether the components fabricated by applying the “other” costs to the materials purchased are ordinarily considered as having a salvage value within the parameters provided by the parties. Other than the “cans,” the only discrete components mentioned by the parties after the “materials” level are the jacket, pilings, and deck. Thus, using our stated formula, we must determine whether any or all of these components are ordinarily considered as having a salvage value. If so, then the “other” costs here in issue do not qualify as IDC but, rather, are part of the costs of acquiring tangible property ordinarily considered as having a salvage value.

In this context, respondent attempted to introduce evidence regarding a purchase by a subsidiary of petitioner in 1974 of a partially constructed jacket from Hamilton Bros., Inc. (herein Hamilton), which had hired J. Ray McDermott & Co., Inc., to build such jacket. The subsidiary intended to modify such jacket to utilize it in a location different from the one for which Hamilton Bros. initially intended to use it. We excluded such evidence as irrelevant because: (1) No showing was made that the jacket was comparable to the ones in issue, and (2) the fact that a jacket may be modified prior to installation to make it usable at an alternate site has no bearing on whether such jacket is reusable at the end of its useful life, which is the crux of the salvage value question.

We are convinced that jackets and pilings installed in the manner in which these were installed cannot ordinarily be considered as having a salvage value. By welding and then grouting the pilings into the jacket legs, recovery of these items becomes economically unfeasible. Conoco's experience with cutting the pilings out of the jacket legs convinced it that it was not a cost-effective activity, and it now disposes of jackets as a matter of course. More importantly, petitioner's experience indicated that out of 51 of these type jackets, only one has ever been moved from one location to another after being installed. We find as a fact that jackets and pilings of the type used in the nine platforms in issue are not ordinarily considered as having a salvage value.

Similarly, the evidence points to a conclusion that decks also are ordinarily considered as not having a salvage value. Petitioner moved only 1 of the 51 decks of the type here in issue from its initial installation site to another site. Of 500 platforms it installed in the Gulf of Mexico (some or all of which may be comparable to the platforms here in issue), Shell Oil Co. reused only one deck, and then only after substantial reconditioning. As we understand the word “ordinarily,” decks of the type here in issue do not ordinarily have a salvage value.

Respondent does seek, in effect, to classify the “cans” fabricated for the subsidiaries as property ordinarily considered as having salvage value. With this in mind, he and petitioner agreed that 15 percent of the stipulated “other” costs constitute the costs of rolling and welding sheet metal into “cans.” If such “cans” are ordinarily salvageable, such costs are not IDC. We find that such “cans” are tangible property not ordinarily considered as having a salvage value. Prior to fabrication, the sheet metal was usable in such a fashion that it would be considered as ordinarily having a salvage value. However, as fabricated, the “cans” were usable only within a structure which itself is not ordinarily considered as having salvage value. Thus, the “cans” became the first unsalvageable component, and the intangible-type costs of fabricating it are IDC.

Contrary to the stipulation, respondent attempts to break out certain costs included in the “material” versus “other” cost breakdown stipulated for three of the Gulf of Mexico platforms, arguing that they are for production purposes and were wrongly categorized as “other” costs. We will not allow respondent to go behind the stipulation, which characterized all of the “other” costs as “labor, fuel, repairs, hauling, supplies, etc.,” and which stated that such costs were expended in the construction of the platforms in issue.

Similarly, we disagree with respondent's contention that petitioner did not prove the allocation between “material” and “other” costs for the Leman-D and Teak-A platforms. The parties stipulated to several Telex messages between petitioner and the fabricator of such platforms, which Telex messages provided the basis for petitioner's allocation. Respondent exclaims that he did not stipulate to the truth of such items, and that is true. However, with one exception, respondent presented no evidence that disputes petitioner's allocation of the relevant costs. Thus, petitioner has carried his burden of proving such allocation, not because respondent agrees to it, but because we believe the only evidence presented on the matter.

Respondent points out that the construction contract for the Teak-A platform specifies that Amoco Trinidad would pay $210,610 for “conductor pipe,” which is casing 30 inches in diameter which is used to conduct the mud used in the drilling of an offshore well back to the platform deck. There is no evidence as to whether the cost of such conductor pipe was included in the “materials” or the labor cost quoted to petitioner in the relevant Telex. Thus, petitioner has failed to prove the characterization of this specific, nonstipulated, item. We must assume that the costs of such item were included in the labor cost quoted, and this amount must be removed from the deductible “other” costs of the Teak-A platform and added to the nondeductible material costs.

Issue 2. Service Station Identification Signs and Lighting Facilities Investment Tax Credit

Two of petitioner's subsidiaries, Maryland and Texas (sometimes herein referred to in the aggregate as American), acquired and placed into service in 1971, after March 31 of that year, new service station identification signs and new service station lighting facilities at a total cost of $3,038,996.65. Petitioner is seeking investment tax credits with respect to such investments. The only disputed issue with respect to petitioner's eligibility for the sought credits is whether the signs and lights, or any separable portions thereof, are “section 38 property.” Section 48(a)(1), as in effect at the time, defined “section 38 property” as “tangible personal property” or as “other tangible property (not including a building and its structural components)” but only if such “other tangible property” was used in specified activities. Petitioner does not contend that the property in question qualifies as “other tangible property.” It does, however, contend that the signs and lights here in issue are “tangible personal property.”

The eligibility of various types of signs has been litigated much of late. The Court of Claims, in Alabama Displays, Inc. v. United States, 205 Ct. Cl. 716, 507 F.2d 844 (1974), and National Advertising Co. v. United States, 205 Ct. Cl. 728, 507 F.2d 850 (1974), and then this Court in Whiteco Industries, Inc. v. Commissioner, 65 T.C. 664 (1975) (herein, the Whiteco case), held that outdoor advertising signs, such as the billboards one sees along the highways, are not “inherently permanent structures” and, therefore, that such signs are “tangible personal property” subject to the investment tax credit. More recently, the Court of Claims dealt with the “7-Eleven” signs, which are very similar to the signs and lights here in issue, holding that they, too, are “tangible personal property.” Southland Corp. v. United States, 222 Ct. Cl. 22, 611 F.2d 348 (1979).

For these purposes, all tangible property constitutes “tangible personal property” unless it is excluded because it is land or an “inherently permanent structure.” Whiteco Industries, Inc. v. Commissioner, supra at 671; sec. 1.48-1(c), Income Tax Regs. The criteria announced in the Whiteco case will control our decision of whether the signs and lights in question, obviously tangible property, constitute inherently permanent structures.

Before we can proceed to the application of such criteria, however, we must determine exactly what property we are inspecting. We can clearly find that the sign heads and lighting fixtures which were bolted onto the appropriate poles are separate assets, the characterization of which should be made separately. Both parties have insisted that we view the concrete bases and poles as integral, inseparable units, seeking an “all-or-nothing” determination on the “section 38 property” issue. Such has been the approach in all of the above-cited cases. However, in all of those cases, the poles have been encased or embedded in the concrete foundations, making such poles and foundations functionally inseparable. In such cases, the courts have felt no need to deal separately with the expenditures for the foundations and for the poles. This analysis is not new; it has been utilized both where the pole-type asset was not deemed “section 38 property,” Roberts v. Commissioner, 60 T.C. 861 (1973), and where it was, Weirick v. Commissioner, 62 T.C. 446 (1974). Three of the signs in issue are constructed in such a fashion, i.e., the poles are embedded in the concrete foundations, that we must deal with them as an integral unit. However, the remainder of the signs and lights are constructed in such a fashion that the poles are simply bolted to the concrete foundations. Such a design is materially different.

In Estate of Morgan v. Commissioner, 52 T.C. 478 (1969), affd. per curiam 448 F.2d 1397 (9th Cir. 1971), we held that certain portable floating boat docks were not “inherently permanent structures,” but that the wooden pilings, which were driven into the submerged harbor bottom, were permanent and, as such, not “tangible personal property.” We there stated:

See also, Ward v. United States, an unreported case (C.D. Cal. 1971, 28 AFTR 2d 71-5043, 71-2 USTC par. 9506).

In our case we think the pilings are components separate from the docks to which they are attached. The pilings are not an integral part of the docks. They are used to serve the same purpose as anchors attached to cables. [[[[ Estate of Morgan v. Commissioner, 52 T.C. 478, 484 (1969).]

Similarly, the concrete foundations for most of the signs and lights here in issue were components separate from the poles. They were designed so that, while the foundations could remain indefinitely and would suffer no damage upon pole removal, the attendant poles could be installed and removed by merely bolting and unbolting such poles to the foundations. Thus, as opposed to the situation where the pole is embedded in the concrete, thus rendering the pole immovable without functionally destroying the foundation, these foundations were not integral parts of the poles which were attached to them. Thus, we will consider the “permanence” of such foundations separately from the poles which were attached to them.

Without extensive consideration, it is clear to us that, under the standards enunciated in the Whiteco case, the sign heads and light fixtures are not affixed to anything in an inherently permanent way. Thus, they are “tangible personal property.”

There remain, therefore, three types of assets to consider: (1) The concrete foundations which were designed to have poles bolted thereto; (2) poles which were designed to be bolted to such foundations; and (3) the three identification facilities, each of which consisted of a pole and the concrete into which the pole was embedded, a la the identification signs in Southland Corp. v. United States, supra. As to each of these assets, six questions must, under the Whiteco holding, be asked in order to determine whether each type asset is “inherently permanent.” The questions, and the answers mandated by the facts herein, are as follows:

(1) “What is the manner of affixation of the property to the land?” Whiteco Industries, Inc. v. Commissioner, supra at 673.

(a) The concrete foundations were firmly embedded in the soil in a fairly permanent way. A hole of 5 to 8 feet in depth was excavated, and the concrete was poured therein. For lighting facility bases, the excavation often was as shallow as 24 inches, though the base for such facilities was often poured integrally with the service station islands.

(b) The poles designed to be affixed to concrete foundations by bolts were so affixed.

(c) The identification facilities consisting of a pole embedded in, as opposed to being bolted to, concrete foundations were obviously affixed to the land by placing the poles in concrete and allowing such concrete to set.

(2) “Is the property capable of being moved, and has it in fact been moved?” Whiteco Industries, Inc. v. Commissioner, supra at 672.

(a) There is no evidence that the concrete foundations which were designed to have poles bolted thereto have ever been moved, and we doubt that they are capable of being moved.

(b) The record is replete with instances where the poles which were designed to be bolted to the appropriate concrete foundations were moved from place to place. They were certainly capable of being removed, stored, and reinstalled at other locations.

(c) Though the identification facilities consisting of a pole embedded in concrete were probably movable ( Southland Corp. v. United States, supra), we have no evidence that they ever were moved.

(3) “Is the property designed or constructed to remain permanently in place?” Whiteco Industries, Inc. v. Commissioner, supra at 672.

(a) All of the evidence herein leads us to the conclusion that the concrete foundations which were designed to have poles bolted thereto were designed and constructed to remain permanently in place.

(b) The poles which were designed to be bolted to the appropriate concrete foundations were, because of such design, meant to be movable. Thus, they were not designed to remain permanently in place.

(c) Petitioner presented no evidence regarding whether the identification facilities consisting of poles embedded in concrete were designed or constructed to remain permanently in place. Though these units seem as capable of being moved as those in Weirick v. Commissioner, supra, petitioner did not focus its proof on them.

(4) “Are there circumstances which tend to show the expected or intended length of affixation, i.e., are there circumstances which show that the property may or will have to be moved?” Whiteco Industries, Inc. v. Commissioner, supra at 672.

(a) All things considered, it appears that American intended the concrete foundations, which were designed to have poles bolted thereto, to be affixed permanently to the land. There is no solid evidence that any were ever removed. American was not required, under its leases and loan agreements, to remove such foundations when a station's affiliation with American ceased.

(b) The poles designed to be bolted to the appropriate foundations were so designed because there are many circumstances that show that such poles might or would have to be moved. When a lease would terminate, American would, though it was not required to, remove signs (and remove or sell the lights) from the premises. Furthermore, if such facilities suffered damage, or if petitioner's logo changed, or if zoning laws adversely changed, American routinely moved these items.

(c) The same circumstances that would have caused American to move the signs and lights in 4(b) above, i.e., damage, logo change, zoning change, would have caused American to move the identification facilities consisting of poles embedded in concrete.

(5) “How substantial a job is removal of the property and how time-consuming is it? Is it ‘readily removable’?” Whiteco Industries, Inc. v. Commissioner, supra at 673.

(a) There is no evidence of any removals of the concrete foundations designed to have poles bolted thereto. We do not believe they would have been readily removable.

(b) The removal of the poles designed to be bolted to the appropriate foundations took from 2 to 24 man-hours of jobsite labor for the identification facilities, and about 1 man-hour of jobsite labor for the lighting facilities. They were readily removable.

(c) Though they were possibly readily removable ( Southland Corp. v. United States, supra), petitioner presented no evidence as to the ease of removal of the three identification facilities consisting of poles embedded in concrete.

(6) “How much damage will the property sustain upon its removal?” Whiteco Industries, Inc. v. Commissioner , supra at 673.

(a) and (b) The parties agreed that, in the course of removing signs and lights that are bolted to concrete foundations, neither sign, light, pole, nor concrete foundation normally sustains any damage.

(c) Petitioner presented no evidence as to what, if any, damage the identification facilities consisting of poles embedded in concrete would sustain upon removal. Though such damage was possibly minimal ( Southland Corp. v. United States, supra, and Weirick v. Commissioner, supra), petitioner has the burden of so proving.

Based upon the answers to the foregoing questions, we conclude:

(a) That the concrete foundations which were designed to have poles bolted thereto are “inherently permanent structures”;

(b) That the poles which were designed to be bolted to the foundations in (a) are not “inherently permanent structures”; and

(c) That petitioner has failed to prove that the poles and concrete bases for the other three identification facilities which consisted of a pole and the concrete into which the pole was embedded are not “inherently permanent structures,” though, with proof such as that which the Court of Claims had before it in the Southland Corp. case, we would likely find that they are not “inherently permanent structures.”

Issue 3. Service Station Identification Signs and Lighting Facilities Depreciation

Petitioner contends that, for those items we have determined are “tangible personal property” under section 48(a)(1)(A), it is entitled to compute depreciation thereon at rates more accelerated than those initially chosen. Petitioner initially categorized the signs and lights in issue as section 1250 property which, if new, was subject to depreciation at a maximum rate of 150-percent declining balance, and which, if used, was subject to depreciation at no greater than a straight-line rate. With that in mind, petitioner elected those maximum rates of depreciation for the relevant signs and lights. Now that it has successfully obtained reclassification of certain of those signs and lights as section 1245 property, petitioner seeks to recompute its depreciation for those recategorized assets under the general rules of section 167(a) through (c). It is undisputed that, had petitioner so elected on the returns filed for those taxable years, it could have computed depreciation on the new signs and lights, under section 167(b)(3) and (c), using the sum of the years digits method, and on the used signs and lights, under the general rule of section 167(a) and section 1.167(b)-O(b), Income Tax Regs., under the 150-percent declining balance method.

Sec. 167(j)(1)(B).

Sec. 167(j)(4).

Those signs and lights that we have found are “tangible personal property” under sec. 48(a)(1)(A) constitute personal property under sec. 1245(a)(3)(A). Sec. 1.1245-3(b)(1), Income Tax Regs. The parties have assumed that this property is “property of a character subject to * * * depreciation.” Thus, for our purposes, the signs and lights that we have found to be “tangible personal property” under sec. 48(a)(1)(A) are sec. 1245 property.

Respondent does not deny that, assuming the signs and lights are section 1245 property, petitioner could have used, had it so elected, the more accelerated methods of depreciation for which it now contends. However, says respondent, petitioner, having elected the less accelerated methods, may not change to a more accelerated method absent the consent of the Commissioner. Sec. 446(e). We must agree.

It is unquestioned that a change in the method of computing depreciation is a change in the method of accounting. Secs. 1.167(e)-1 and 1.446-1(e)(2)(ii)( a), Income Tax Regs. Absent a change from an accelerated method to straight line (see sec. 167(e)), the Commissioner's permission must be obtained to change from one depreciation method to another. An exception to this rule has arisen where a taxpayer initially chose an erroneous, legally unavailable method, in which case, when such method is disallowed, the taxpayer may choose an allowable accelerated method, as opposed to being forced to utilize the straight line method. Buddy Schoellkopf Products, Inc. v. Commissioner, 65 T.C. 640, 653 (1975); Foley v. Commissioner, 56 T.C. 765 (1971). However, petitioner herein did not choose a legally unavailable method but, instead, chose methods which were legally acceptable, though maybe not most advantageous. In such a case, the taxpayer must seek the Commissioner's permission. Foley v. Commissioner, supra.

Petitioner cites several cases in an attempt to circumvent this rule, all of which are either distinguishable or clearly inapposite. Respondent must prevail on this issue.

Issue 4. Minimum Tax on Tax-Preference Items

Petitioner computed a minimum tax on tax-preference items under sections 56 through 58 for the taxable years before us. Respondent recalculated such amounts because of his determinations on the other issues before us. The correct amount, it is agreed, must be determined in light of our holdings on such other issues. However, in his petition, petitioner claimed that such minimum tax is deductible. It argues herein that, although the minimum tax is constitutional, it is an excise which, although not specifically enumerated in section 164, is deductible as an ordinary and necessary business expense. See sec. 1.164-2(f), Income Tax Regs. It vigorously and imaginatively argues that the minimum tax is not a Federal income tax and, therefore, that it eludes the grasp of section 275 which disallows the deduction of Federal income taxes. Since the trial and briefing of this case, this issue has been decided in favor of the Commissioner by this Court in Graff v. Commissioner, 74 T.C. 743 (1980). See United States v. Darusmont, 449 U.S. 292 (1981). We, therefore, hold that the minimum tax paid by petitioner is a Federal income tax and, as such, is not deductible under section 275.

Decision will be entered under Rule 155.