1986 U.S. Tax Ct. LEXIS 67 | Tax Ct. | 1986
Lead Opinion
The Commissioner determined deficiencies in petitioner’s Federal income tax for the taxable year 1974 in the amount of $80,813,428 and for the taxable year 1975 in the amount of $166,316,320. Petitioner and respondent, with the approval of the Court, agreed that certain issues would be severed and tried at a special trial session which was held at Dallas, Texas.
One of the issues to be tried was designated by the parties as the “Intangible Drilling and Development Costs” issue. The issue for decision is whether petitioner may deduct as IDC under section 263(c),
FINDINGS OF FACT
Some of the facts have been stipulated. The stipulation of facts and accompanying exhibits are so found and incorporated herein by reference.
Gulf Oil Corp. (hereinafter referred to as petitioner or Gulf) is a corporation organized under the laws of the Commonwealth of Pennsylvania with its principal office in Pittsburgh, Pennsylvania. During the taxable years at issue, Gulf and certain of its subsidiary corporations constituted an “affiliated group” as that term is defined in section 1504. Petitioner, directly and through its foreign subsidiaries and affiliates, is engaged in world-wide exploration, development, production, purchase, and transportation of crude oil and natural gas, and in the manufacture, transportation, and marketing of petroleum products.
Gulf, as the common parent of an affiliated group of corporations, timely filed consolidated Federal income tax returns for its taxable years 1974 and 1975 on behalf of itself, and certain of its subsidiary corporations, with the Office of the Internal Revenue Service at Pittsburgh, Pennsylvania.
Petitioner maintained its books of account for the taxable years in issue on the accrual method of accounting using the calendar year as its taxable year. Prior to and during the taxable years at issue, petitioner elected to deduct as current expenses all intangible drilling and development costs (hereinafter sometimes referred to as IDC) in accordance with section 263(c) and section 1.612-4, Income Tax Regs. The IDC costs at issue were incurred with respect to properties in the Gulf of Mexico and in the North Sea.
During the taxable years in issue, petitioner incurred costs to design and construct self-contained drilling and production platforms' to be installed on oil and gas properties located in the Gulf of Mexico in which it had a working or operating interest (hereinafter referred to as a working interest). The working interests were obtained pursuant to either a lease or assignment of a lease with respect to each property. The leases generally specify that the platforms are to be removed from the installation site within 2 years of the end of production or upon obsolescence.
The year placed in service, location of the platform, identifying number of the platform, and petitioner’s share of the working interest were as follows:
Year placed in service Platform location Platform identification Petitioners share working interest
1975 South Pass Block 62 South Pass 62A 50%
1975 South Pass Block 61 South Pass 61B 100
1975 Eugene Island Block 313 Eugene Island 313A 50
1976 Eugene Island Block 313 Eugene Island 313B 50
1976 Grand Island Block 93 Grand Island 93C 45
1975 West Cameron Block 266 West Cameron 266A 50
1977 South Pass Block 77 South Pass 77A 33Ms
1976 Vermilion Block 23 Vermilion 23A 331/3
1976 South Pass Block 62 South Pass 62B 50
Year placed in service Platform. location Platform identification Petitioners share working interest
1975 South Timbalier Block 37 South Timbalier 37A S3Vs%
N/A South Timbalier Block 361 South Timbalier 36D 100
1975 South Timbalier Block 36 South Timbalier 36B 3314
1 This platform was used primarily for soil testing purposes rather than for production.
After installation, wells were drilled from each of these platforms in the Gulf of Mexico. Set forth below for each self-contained drilling and production platform is the operator, the number of wells drilled, the number of wells producing as of the time of trial, and the type of production from the wells, and certain characteristics of the platform.
Wells drilled/ Type of Operator producing wells Gulf 34/19 19 oil Platform name South Pass 62A Platform 8 main piles 4 skirt piles 24 well slots
South Pass 61B Gulf 2/0 N/A 8 pile 15 well slots
Eugene Island 313A Texaco 18/7 6 oil 1 gas 8 pile 15 well slots
Eugene Island 313B Texaco 21/10 7 oil 3 gas 8 pile 18 well slots
Grand Island 93C Mobil 6/6 6 gas 8 pile 12 well slots
West Cameron 266A Gulf 13/4 4 gas 8 pile 18 well slots
South Pass 77A Chevron 16/11 3 oil 8 gas 4 pile 12 well slots
Vermilion 23A Mobil 10/5 5 gas 8 pile 18 well slots
South Pass 62B Gulf 9/7 7 oil 8 main piles 4 skirt piles 24 well slots
South Timbalier 37A Gulf 15/6 4 oil 2 gas 8 pile 2 well slots
South Timbalier N/A 36D1 N/A N/A N/A
South Timbalier N/A 36B 21/15 5 oil 10 gas 8 piles 21 well slots
1 This platform was used primarily for soil testing purposes rather than for production.
The offshore platforms at issue in the Gulf of Mexico are all of one basic type, namely self-contained drilling and production platforms. This differs from the tender platform, which is used for installations closer to shore, and which was used more frequently before the mid-1960’s. A tender platform is so-called because it is necessary to anchor a barge or tender alongside the platform during drilling to accommodate and store part of the drill pipe and other material and equipment used in drilling. A self-contained platform is so named because some or all of the drill pipe and other materials and equipment used in drilling can be accommodated and stored on the platform. The self-contained platform was developed to decrease the number of work stoppages due to rough weather that required disconnecting the tender and it is also generally larger and heavier than a tender platform.
Prior to the time of completion of a platform, there are four phases that may be briefly described as follows: (1) The onshore design and construction phase; (2) the loading 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.
Normally, after acquisition of the lease, an exploratory well is drilled, usually by means of a jack-up rig, in order to confirm the economic feasibility of placing a platform on the lease. If the well is a producer, the location for the platform is selected by Gulf or the operator (with the concurrence of the other working interest owners), and the design criteria for the necessary platform are developed.
Each platform is designed and constructed for the conditions at the specific location at which it is to be installed. No two platforms have the same design criteria, although the basic structural design is similar for all self-contained drilling and production platforms. Gulf’s design and engineering personnel gather information with respect to the proposed platform site and develop the basic design for each specific platform. They consider soil conditions, storm ratings, water depths, tides, wave forces, and well spacing. These factors affect the 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 steel, size of members, and type of bracing. They utilize computer-generated design programs. The soil data includes the strength and adhesion characteristics of the soil which determine how deep the piles should and can be driven and the capacity that the pile can accommodate. The meteorological data are based on both normal conditions and the conditions that might be encountered by the platform during the worst storm that could be expected during a 100-year period (otherwise known as a 100-year storm). Water depth is critical in the design process, as are the 100-year storm waves, the current, and the tides. Wave loading affects every member of the structure because of the lateral, or horizontal, stress or load placed on the structure. The location is also important as the soil and water conditions will vary if the site is close to the mouth of a river or, conversely, many miles offshore. For example, at the mouth of the Mississippi, the additional stresses caused by the variations in soil conditions and water depth require the use of skirt piles to protect the main piling from lateral stress. The structure must also be designed to withstand the maximum live drilling loads or movable loads, caused by activity on the platform, as well as the vertical or dead load caused by the mass and weight of the structure. A critical external criteria that must be determined is the function to be served by the platform, i.e., the number of wells to be drilled, the depth to which the wells are to be drilled, the type of drilling, and the method of transporting the hydrocarbons to the shore.
Once the design has been completed, the plans and specifications are prepared, at least partially by computer, and sent out for bid. The successful bidder then constructs the structure under the supervision of Gulfs employees. The process of fabrication or construction and the process of installation are not always done by the same contractor. If not, the completed structure is stored on shore until the barges arrive for the transportation of the platform to the site.
Each of the platforms in the Gulf of Mexico in controversy consisted of three major components which were constructed onshore: (i) The deck, (ii) the jacket, and (iii) the piling. In general terms, the deck section is the portion of the structure that holds the drilling rig, drill pipe, and production equipment; the jacket is the underwater bracing system which is put into the water first; and the pilings are driven through the legs of the jacket to anchor the platform.
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 used with a different jacket and at a different location than that originally contemplated, but generally only after structural analysis and expensive modifications. 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 of either decks or jackets are undertaken only if they are considered to be economically feasible, taking into consideration all of the requisite costs.
During and after the construction process, a platform jacket, subject to economic constraints, can be modified for use in water depths varying by 5 to 10 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, although this was not Gulf’s practice. Such a procedure will tend to accelerate drilling projects and reduce “lead time.” This is accomplished by designing the platform deck to withstand the most severe requirements that may reasonably be anticipated, which is more expensive than designing each platform to the minimum specifications required by installation in a particular location. In some instances, decisions have been made not to use platform components once constructed. Such components then become surplus and are available for purchase, modification, or other use.
After being constructed onshore, the three major components of each platform in the Gulf of Mexico are loaded on a ship or barge for transportation to the platform location. The barge is towed to the installation site and the jacket is skidded off the barge into the water. The upending procedure consists of controlled flooding of the legs of the jacket, which are steadied by a derrick hook. Once the jacket is sitting on the bottom, it is leveled with the use of surveying instruments and is then ready for driving of the pilings.
Pilings are used to provide structural stability by means of the friction between the piling and the soil. Several pilings are set before the driving process begins. Frequently the piling will penetrate to a depth between 30 and 50 feet as a result of its own weight before being driven. Once set, the piling is driven by a hammer to a specified depth. Sections of piling are then added to the previously driven section. The length of the piling used and the depth to which it is driven are controlled largely by the weight of the hammer used to install it. Petitioner makes allowances for overdriving and underdriving. Underdriving means that the piling can be driven to a lesser depth than it was designed for; overdriving means that the piling can also be driven to a deeper depth than that for which it was designed.
Once the piling is driven to the specified depth, the grouting process begins. Grouting, a specialized form of cement without aggregate, stiffens the structure by filling the gap or annulus between the leg of the jacket and the piling. Structures that are designed to be moved are not grouted. Gulf grouts the legs of all of its self-contained drilling and production platforms.
After installation and leveling of the jacket and completion of the grouting, the deck section is lifted and positioned upon the structure. The deck column has stabbing guides that fit into the top of the piling. The deck is then welded in place. The self-contained drilling and production platform, once installed, begins its productive life.
During the taxable years in issue, petitioner also incurred costs to design and construct five large platforms to be installed on four oil and gas properties located in the North Sea in which it had a working interest. Gulf was a member of the Statfjord Group, consisting of licensees in areas of the North Sea governed by Norway and the United Kingdom and unitized into one operational unit. Mobil was selected as operator for the development of the unitized field. The year placed in service, block location of the platform in the North Sea, identifying number of the platform, and petitioner’s share of the working interest were as follows:
Year placed Platform in service location Petitioners share of Platform identification working interest
1977 211/23 Dunlin/No. 3016, 4001, 5501 9.80%
1984 (est.) 211/28 Hutton/No. 4013 16.70
1977 33/9 Statfjord A/No. 5502 5.30
1981 33/12 Statfjord B/No. 5503 5.30
1977 211/18 Thistle/No. 4015 5.33
Wells were drilled from each of these platforms following installation. Set forth below for each of the platforms, all of which are self-contained drilling and production platforms, is the operator, the number of wells drilled, the number of wells producing as of the time of trial, the type of production from the wells, and certain characteristics of the platform:
Platform name Wells drilled/ Type of Operator producing wells Platform
Dunlin Shell 27/18 oil 4 column gravity based concrete 48 well slots
Hutton Conoco N/A N/A tension leg 32 well slots
Statfjord A Mobil 28/14 oil 3 column gravity based concrete 42 well slots
Statfjord B Mobil 11/9 oil 4 column gravity based concrete 42 well slots
Thistle Britoil 44/32 oil 4 column steel 60 well slots
The Hutton platform was to be installed in 1984. Once this platform was installed, the operators planned to drill 14 wells, 2 of which will be for oil production, and 12 of which will be for water injection.
The general sequence of events from design through installation is the same for the platforms in the North Sea as for platforms in the Gulf of Mexico: the design and construction phase; the load-out or tie-down phase; the transportation phase; and the installation phase. Differences in design, construction, and installation are caused by constraints imposed by compliance with Government policy and the functional needs to insure economic productionfrom the particular field, as well as physical constraints imposed by the much greater depth of the water and ferocity of the weather.
The design process for the North Sea platforms is far from routine, due both to the physical conditions and to the involvement of not only the various working interest owners, but also the Governments of Norway and the United Kingdom. The physical conditions are far less placid than those in the Gulf of Mexico. For example, the usual design criteria for a 100-year storm in the upper North Sea includes waves from 95 to 100 feet high and winds from 145 to 150 miles per hour. Although the design criteria, plans, and specifications for the plans for each of these platforms were joint efforts of a number of different entities, Gulf participated to the fullest extent possible.
Unlike the platforms in the Gulf of Mexico, the platforms in the North Sea varied in type. The Thistle platform was a steel-jacketed platform of a much larger size than the platforms in the Gulf of Mexico. A second type was the concrete and steel, gravity base structure used for the Dunlin, Statfjord A, and Statfjord B platforms. The final type of platform at issue was the tension leg design used for the Hutton platform.
The design criteria were specific to the soil and environmental conditions expected at each individual site. Furthermore, each platform was specifically designed both for its physical location and for the functions that it was to fulfill in terms of number and depth of wells desired, well spacing, and the size and configuration of the drilling rigs to be used. The platforms are also designed specifically for other characteristics of the oil field at which they are to be installed, for example, the ratios of oil and gas expected upon production.
In the case of the Hutton platform, the technology was a considerable advancement from that used in previous platforms, requiring the participation of Gulf, Conoco, Amoco, and a consortium of other major oil companies. The design was begun in 1979, with construction beginning in 1981. As the plans developed, the original planned design had to be enlarged thereby affecting the size and number of the tethers or anchor lines needed to attach the platform to the sea bottom. The tethers and tension legs are designed for a particular water depth and a particular load. The platform, as constructed, is not as rigidly fixed to the bottom as the Gulf of Mexico platforms, but is designed to “give” or allow the platform to lean slightly with the forces of the waves. The primary benefit of the initial buoyancy of the North Sea platforms, including the Hutton platform, is that they are less expensive than they would otherwise be to move to the installation site and may be easier to remove for disposition upon completion of their useful lives.
The installation process is different for the self-contained platforms in the North Sea than for the installation process for the sélf-contained drilling and production platforms in the Gulf of Mexico. Because the structures involved are larger than the available barges, flotation is built into the structures so that the deck or module support frame can be floated out to the site as one unit and then flooded and fixed into place by means of multiple piles or tethers. For example, the Thistle platform was installed on top of forty-two 54-inch piles which were driven to a depth of 450 to 470 feet below the surface of the sea bed. The gravity based platform also relies upon the use of concrete to maintain itself in a particular location by the sheer mass and weight of the platform. Such platforms also offer the advantage of additional storage in the hull which is used to store oil for loading onto tankers before the installation of pipelines. The installation of each of these types of platforms: the large steel jacketed platform, the tension leg platform, and the gravity type concrete platform, is a lengthy process involving towing, filling with ballast, assembling, and grouting. Frequently the buoyancy of the platforms is not adequate during towing to transport all of the necessary equipment, thus requiring the use of barges with derricks, and an even lengthier installation period. The platforms in the North Sea are all buoyant to some extent, at least until the ballast system is filled, and are thus generally referred to as floating. The buoyancy makes it possible to readjust the location of the platform slightly so long as the procedure for filling with ballast is still active.
With respect to the platforms in the North Sea, petitioner was unable to identify the portion of its total costs deductible as IDC prior to filing its Federal income tax returns for the taxable years in issue. Therefore, petitioner did not deduct any such costs on its returns as originally filed. Upon audit, petitioner filed claims for refund based upon the deduction of such costs. For the taxable year 1974, petitioner claimed IDC deductions relating to platform costs of $3,631,075. For the taxable year 1975, petitioner claimed deductions relating to platform costs of $10,558,200.
Offshore platforms, including those designated as “drilling” platforms, are long-lived assets, designed for useful lives in excess of 20 years. The loads placed upon the platforms and the corrosion caused by weather and water eventually destroy the structure. 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 of the wells or the drilling of one or more additional wells occurs. 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 being drilled. All of the platforms in controversy in this case were still in place as of the time of trial and, with the exception of the Hutton platform, are actively producing oil or gas. Shortly after installation, each platform has been predominantly or entirely involved in production rather than in drilling and development.
The process of removal of a self-contained grouted platform of the type used by Gulf in the Gulf of Mexico would be a multistep process. All reusable equipment such as crew quarters and drilling and production equipment would be removed from the platform and salvaged. All of the wells but those necessary to supply the power necessary for the removal process would be shut in or plugged and the pipelines would be destroyed. The process of platform construction would then be reversed, with removal of the superstructure first. The piling would then be cut and discarded. Shaped explosive charges can be used to cut pilings at or below the surface of the sea bed. This enables the platform to be removed for disposition, but not necessarily for placement at another site. The grouting would have to be removed, which is a tremendously expensive operation, and is normally done only onshore. Gulf has never removed the grouting from a structure. The jacket, with or without the pilings, would then either be towed away or floated away using floating tanks. Removal does not, however, necessarily mean that the structure could be economically reused or relocated, even if the design criteria at the new location were identical to the original location. Substantial and costly modification would be required. The specific design of the deck and the jacket once constructed for the original installation would preclude economical reuse of these components with new components even if the structures were in good condition. Further, although the technology existed for removal of the platforms during the taxable years at issue, the technology necessary for the reinstallation of these particular platforms was only hypothetical at that time.
Although petitioner has upwards of 423 platforms in the Gulf of Mexico, Gulf has never removed and relocated a self-contained drilling and production platform. Gulf has only removed one self-contained drilling and production platform, the South Pass 61A platform, when it was damaged by Hurricane Camille shortly after its installation. The jacket, piling, and deck were removed, towed to deep water, and sunk. Production from another platform, the South Pass 61B platform, ceased shortly after drilling. Despite study, Gulf has failed to find an economical use for the platform or any of its components, and has determined to solicit bids to scrap it.
Some platforms or parts of platforms of types different from those involved here were removed and reused by others before or during the taxable years at issue. In 1966, Humble moved a tender-type structure approximately 30 miles from the South Pass 36A lease to the West Delta 73 lease. In 1968, Gulf moved a platform from Block 82, Grand Isle, to West Delta Block after substantial modifications. Both locations were in the same depth of water. In 1975, Shell moved a shallow water structure from a 30-foot depth to a 40-foot depth. In 1980, Sun moved a drilling deck approximately 75 miles. In 1982, portions of the Pemex platform in the Gulf of Mexico off Padre Island were removed after a blowout and fire, and reset approximately 700 yards away from its initial site. In each situation described above, an important portion of the structure was replaced in the reinstallation process.
The hypothetical process of removal of platforms in the North Sea is complicated by the complexity of the design. Gulf and the other owners of working interests in the North Sea fields have studied at length the problem of the disposition of the North Sea platforms, as it is both a technological and political problem. Removal will eventually be necessary, however, as international law and the relevant leases require their removal upon obsolescence. The cost of removal for each North Sea platform has been estimated at between $200 million and $400 million. Even the “floating” platforms are partially grouted in place, which makes them extremely difficult to remove. The process of removal would also require decommission and deactivation of all of the equipment, which would destroy its value for resale, even assuming that the underlying superstructure was still in good condition. The most frequently discussed method of removal is to take sufficient weight off the top, deballast, and pump underneath the platform to make the platform more buoyant, possibly add additional buoyancy tanks, and then tow the platform 300 miles to deep ocean dumping grounds. While the platforms in the North Sea have been described as “floating,” their buoyancy is insufficient to allow relocation and is used simply to facilitate the installation and removal process.
The platforms cannot be simply moved to another location and reused because of their site-specific design, technological obsolescence, and damage resulting from corrosion and metal fatigue. Although there has been some discussion in the industry that such platforms might be reusable in another oil field, the platforms, once completed, are specific to the particular site at which installed. The procedures used for a reflotation and removal would effectively cause or complete destruction of the platform and all possibility of reutilizing the platform. The proposals for removal of the North Sea platforms are largely hypothetical as none of the North Sea platforms, as of the time of trial, have been either removed or refloated, much less relocated.
Each of the platforms in controversy, whether installed in the Gulf of Mexico or the North Sea, was designed, constructed, transported, and installed under petitioner’s supervision (or the supervision of the operator of the oil and gas property) by independent contractors. With the exception of the Hutton platform, which was not installed as of the time of trial, each of the other platforms in controversy in this case are located at the site at which they were initially installed. Petitioner did not intend to reuse any of the platforms in controversy at any other location nor were any plans formed by which such reuse would be technologically or economically feasible.
The following schedule shows, for each of the self-contained drilling and production platforms 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.
GULF OF MEXICO PLATFORMS
Type of Water Weight in tons Platform1 name platform Piling Conductors depth Jacket Deck
South Pass 62A 8 pile 2200 780 340 3800 950
South Pass 61B 8 pile N/A 230 1110 375 1195
Eugene Island 313A 8 pile N/A 236 1450 568 N/A
Eugene Island 313B 8 pile N/A 240 1468 658 N/A
Grand Island 93C 8 pile N/A 218 N/A N/A N/A
West Cameron 266A 8 pile 165 80 527 408 477
South Pass 77A 4 pile N/A 220 2385 650 2460
South Pass 62B 8 pile 873 375 2990 940 2336
South Timbalier 37A 8 pile 269 57 664 378 436
South Timbalier 36B 8 pile 57 664 378 436 269
1 The requisite numbers for completion of this table for Vermilion, 23A, and South Timbalier 36D were not provided to the Court.
NORTH SEA PLATFORMS
Water depth Platform name Type of platform Total weight (metric tons)
495 Dunlin 4 column gravity based concrete 253,723
Hutton tension leg 47,400 GO Cn
Statfjord A 3 column gravity based concrete 650,000 <1 00
476 Statfjord B 4 column gravity based concrete 781,000
530 Thistle 4 column steel 31,000 (jacket only)
On July 1, 1982, the Commissioner timely issued a statutory notice of deficiency to petitioner, determining deficiencies in the amounts of $80,813,428 for the taxable year 1974, and $166,316,320 for the taxable year 1975. The Commissioner disallowed the deductions for “IDC type” costs in respect of offshore drilling and development platforms located in the Gulf of Mexico in the amounts of $6,752,598 for the taxable year 1974, and $5,459,328 for the taxable year 1975. After concessions and adjustments, the amounts of IDC which are still in dispute for IDC costs with respect to the platforms in the Gulf of Mexico are $356,888 for the taxable year 1974, and $6,106,547 for the taxable year 1975, divided among the respective platforms as follows:
Amounts disallowed
Platform 1974 1975
South Pass 62A $525,054 $641,273
South Pass 6 IB (363,454) 812,214
Eugene Island 313A 129,347 1,926,360
Eugene Island 313B 35,556
Grand Island 93C 34,631 652,674
West Cameron 266A 31,310 1,097,808
South Pass 77A 628,005
Vermilion 23A 215,097
South Pass 62B 97,560
Total 356,888 6,106,547
With respect to the platforms in the North Sea, the Commissioner disallowed 60 percent of the IDC type costs claimed by petitioner in the amounts of $2,178,645 for the taxable year 1974, and $6,334,920 for the taxable year 1975. The balance of the deductions claimed by petitioner relating to platform costs in each of the 2 taxable years was allowed as a deduction by the Commissioner, and the deduction of such costs is not in controversy.
OPINION
The issue is the deductibility of costs claimed as IDC with respect to offshore platforms in the Gulf of Mexico and the North Sea. The determination of the Commissioner in his statutory notice of deficiency is presumptively correct, and petitioner has the burden of disproving each individual adjustment. Welch v. Helvering, 290 U.S. 111 (1933); Rule 142(a). In addition, petitioner bears the burden of proving the overpayments which it claims. Petitioner, therefore, bears the burden of proving that the costs at issue qualify for deduction as intangible drilling costs.
Respondent contends that the costs at issue are capital expenditures under section 263(a), and that the costs do not qualify for the optional IDC treatment under section 263(c) and section 1.612-4, Income Tax Regs. His basic position is that the costs were incurred in the acquisition of tangible property ordinarily considered to have salvage value. Petitioner contends that the costs incurred do qualify for the optioned IDC treatment as neither the platforms at issue nor their major components (deck, jacket, and pilings) can ordinarily be considered to have salvage value.
The general rule of section 263(a) is that no deduction shall be allowed for “any amount paid out for new buildings or for permanent improvements or betterments made to increase the value of any property or estate.” Section 263(c) and section 1.612-4, Income Tax Regs., promulgated thereunder, are an exception to the general rule, and provide that taxpayers have the option to deduct, rather than capitalize, intangible drillings costs, as that term is defined in the regulations.
The history of the intangible drilling costs deduction is a complex one, which has been detailed at length elsewhere. Exxon Corp. v. United States, 212 Ct. Cl. 258, 547 F.2d 548, 553-555, 563-564 (1976) (hereinafter sometimes referred to as the Exxon case); Standard Oil Co. (Indiana) v. Commissioner, 68 T.C. 325, 345 n. 9 (1977). The salient points are that the option to deduct IDC was originally allowed without the benefit of statutory authority; then it was questioned in the courts, and finally received congressional imprimatur
SEC. 263(c). Intangible Drilling and Development Costs in the Case of Oil and Gas Wells. — Notwithstanding subsection (a), regulations shall be prescribed by the Secretary or his delegate under this subtitle corresponding to the regulations which granted the option to deduct as expenses intangible drilling and development costs in the case of oil and gas wells and which were recognized and approved by the Congress in House Concurrent Resolution 50, Seventy-ninth Congress.
The regulations concerning the deduction of IDC’s have remained remarkably consistent in both language and policy, from their inception in 1916 (T.D. 2447 (unpublished), relating to the Revenue Act of 1916) to the present. Section 1.612-4, Income Tax Regs., which is conceded by both parties to contain the controlling criteria for the decision of this case, provides:
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 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—
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(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.
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(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 recoverable through depreciation.
We have previously considered the application of the provisions governing the deduction of intangible drilling costs at length and in detail, most recently in Standard Oil Co. (Indiana) v. Commissioner, 77 T.C. 349 (1981) (hereinafter sometimes referred to as the Standard Oil case). In that opinion and other opinions by this Court, the Court of Claims, and most recently, the U.S. District Court for the Southern District of Texas, the regulations have been interpreted and applied in accord with the fact that “Congress favors a liberal interpretation of the regulation.” Texaco, Inc. v. United States of America, 598 F. Supp. 1165 (S.D. Texas 1984) (hereinafter sometimes referred to as the Texaco case); Standard Oil Co. (Indiana) v. Commissioner, 77 T.C. at 386-387; Gates Rubber Co. v. Commissioner, 74 T.C. 1456, 1475 (1980), affd. 694 F.2d 648 (10th Cir. 1983); 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. Respondent urges us to review our position, and 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). We see no reason to change our view that an overly restrictive approach to these regulations is inappropriate in light of the view in Congress that the IDC option is 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 opinions in Exxon, Standard Oil, and Texaco dealt with many of the arguments set forth by respondent and petitioner in the instant case at length and in detail. The primary difference is that the platforms at issue in this case are of a different type and placed in different locations them those considered previously.
We, therefore, apply the provisions of section 1.612-4(a), Income Tax Regs., in the same fashion as in the prior cases, leaning heavily on the able work that has been done before. As the regulation states, the types of costs subject to the IDC option are described as “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.” As noted above, all of the costs at issue were incurred with respect to platforms that were initially used for drilling and subsequently used for production and drilling operations as appropriate. The costs were incurred either directly by petitioner or by petitioner’s contractors, again in accord with the regulation. Finally, the costs were incurred with respect to the design and construction of offshore drilling and production platforms that are essential for the drilling of wells and the preparation of wells for the production of oil and gas. Sec. 1.612-4(a)(3), Income Tax Regs. These are the specific types of costs included within the regulation.
The regulation limits the availability of the IDC option to “expenditures for those drilling and developing items which in themselves do not have a salvage value.” However, IDC “Eire not considered as having a salvage value, even though used in connection with the installation of physical property which has a salvage value.” “InstEillation” includes construction at a location other than the actual site upon which the platform is finally installed. Exxon Corp. v. United States, 547 F.2d at 556. The regulation distinguishes nonoptionEil items, which include “expenditures by which the taxpayer acquires tangible property ordinEirily considered as having a salvage value.” Sec. 1.612-4(c)(l), Income Tax Regs. Examples of such items include “actual materials in those structures” Emd “drilling tools, pipe, casing, tubing, tanks, engines, boilers, machines, etc.”
Past opinions have differentiated between the “actual materiEils” referred to in section 1.612-4(c), Income Tax Regs., and other costs and concluded that the physical and tangible materials that are trEmsformed via labor, fuel, etc., into the desired assets for drilling are the “actual materials” rather than the completed platforms or their major components (deck, jacket, piles, etc.) as urged by respondent. The result of this conclusion is that the availability of the IDC option for the costs at issue will depend on whether these costs are expenditures by which the taxpayer has acquired tangible property ordinarily considered as having salvage value. Sec. 1.612-4(c), Income Tax Regs.
We hold that the “not ordinarily considered as having a salvage value” test contained in section 1.612-4(c), Income Tax Regs., is an objective test to be applied to the types of platforms involved here as used in the oil industry in general, rather than a more limited test based upon the use by a particulEir taxpayer who claims the IDC election. This is the manner in which the Court of Appeals for the Tenth Circuit viewed the use of surface casing in Harper Oil Co. v. United States, 425 F.2d 1335 (10th Cir. 1970), and the manner in which the U.S. District Court for the Southern District of Texas more recently viewed the use of offshore platforms in Texaco, Inc. v. United States, supra.
The parties differ on the point in time at which we should examine the platforms to see whether they are ordinarily considered as having a salvage value. Petitioner contends that the examination should be made at the time of acquisition. Respondent contends that the examination should be made at the time drilling is terminated. This was the position of the Government which the court rejected in Texaco, Inc. v. United States, supra. We agree with petitioner and the Texaco analysis.
Respondent reasons that once the platform is no longer used for drilling, it is no longer at risk, and because IDC and risk are so inextricably related, the examination should be made when drilling ceases. We have consistently held that IDC and risk are inextricably related. Standard Oil Co. (Indiana) v. Commissioner, 68 T.C. at 350. The risk referred to, however, is the general risk of exploration for, drilling, and producing hydrocarbons and that risk does not cease at an arbitrary time prior to the end of the use of the platform in the taxpayer’s trade or business. Drilling and production are not mutually exclusive, as shown by the record before us. Drilling customarily continues after production is attained on the first well and will usually continue until all locations have been explored. Production may or may not continue during this period. Therefore, we cannot,agree that examination of the platform for its possible salvageability should be made at the end of its use for drilling, even if that date necessarily coincided with commencement of production, which it rarely does.
As a practical matter, the determination of whether a platform can ordinarily be considered to have salvage value must be made at the time of acquisition. To find otherwise would mean that a platform from which production is attained would not qualify for IDC. Congress never indicated any intent to allow the IDC election only for unsuccessful efforts to find hydrocarbons. Furthermore, delay in determining salvageability would leave in limbo for periods extending into several annual accounting periods the question as to whether a particular platform would qualify for the IDC election or would, instead, be subject to an annual deduction for depreciation.
The application of the IDC election for platforms must be consistent with the depreciation regulations because if the platforms do not qualify for IDC they do qualify for depreciation. Section 1.167(a)-l(c), Income Tax Regs., specifically provides that the amount of salvage value is determined at the time the asset is acquired. It necessarily follows that the determination of whether the asset is ordinarily considered as having a salvage value under section 1.612-4(c), Income Tax Regs., must be made at the same point in time.
If the salvageabihty were determined at the end of the drilling period it would bifurcate the period of the useful life of the platform. This would be also contrary to section 167 because it defines useful life as the period over which the asset may reasonably be expected to be useful to the taxpayer in his trade or business or in the production of income. Sec. 1.167(a)-l(b), Income Tax Regs. The platform, once drilling ceases, continues in use to the taxpayer as a production platform. It would be absurd to hold that a single platform has one useful life while being used for drilling purposes under section 1.612-4(c), Income Tax Regs., and another useful life for production purposes under section 1.167(a)-l(b), Income Tax Regs.
We have previously stated, with the support of the regulations, that “the salvageability of the item in question should be determined with an eye toward the ordinary manner in which it is used,” (Standard Oil Co. (Indiana) v. Commissioner, 77 T.C. at 399), a view which the District Court in Texaco notes “reconciles clearly with the Harper Oil analysis.” Texaco, Inc. v. United States, supra at 1175. The platforms at issue are designed, constructed, and installed with the purpose of both drilling and production, oftentimes simultaneously. The useful life of the platforms is readily determinable by reference to obsolescence and fatigue. When a platform ceases to be used in a taxpayer’s trade or business is an identifiable event easily ascertained. The cessation of drilling, on the other hand, depends upon many factors and conditions not readily ascertained. Furthermore, determining salvage value at this time disregards the demonstrated fact that the useful life includes not only the time spent drilling, but also the much longer period of production.
An objective review of the evidence indicates that the platforms at issue and their components are not, at the time of acquisition, ordinarily considered as having a salvage value. Although petitioner has upwards of 423 platforms in the Gulf of Mexico, it has removed only a small number of them before and during the taxable years at issue, and reinstalled components thereof rarely and only after substantial modifications. None of the removed platforms were either the size, complexity, or type of self-contained drilling and production platforms. It is no more than the hypothetical opinion of respondent’s expert that the platforms at issue could, in fact, be relocated and reused or that there are locations for which the design specifications would be identical.
Respondent urges that the particular platforms at issue need not be salvageable if they are a type of asset that is ordinarily considered as having a salvage value. Petitioner has, however, amply demonstrated that, at time of acquisition, little, if any, salvage value was anticipated. The occasional incidents cited by respondent in which platforms were removed and reinstalled by entities other than Gulf were of a different type, in different depths of water and conditions, and reinstalled only after modifications. Further, the cited salvage operations occurred frequently as a result of unforeseeable disaster rather than being the routine type of salvage that occurs at the end of the ordinary useful life to the taxpayer. Sec. 1.167(a)-l, Income Tax Regs. “Ordinary” necessarily implies that salvage operations occur more frequently than extremely rarely. Respondent’s evidence that decks belonging to unknown parties which may or may not have ever been installed as part of platforms were available for resale in years after the taxable years at issue does not persuade us to alter our conclusion that neither the platforms nor the major components thereof ordinarily have salvage value.
The evidence also establishes that the platforms, as a matter of economics, have no demonstrated salvage value at the end of their 20-year estimated life. Indeed, Gulf accrues an annual liability on its books to account for the estimated cost, in excess of scrap value, of dismantling and removing each platform at the end of its normal useful life. Gulf’s actual experience confirms that the platforms do not have a salvage value. Moreover, as each platform is designed and constructed for use at a specific site, the evidence establishes that as a practical matter neither a platform nor its major components are salvageable. The hypothetical methods of salvage and reuse described by respondent’s expert are not borne out by the experience of petitioner or by other owners of platforms in either the Gulf of Mexico or the North Sea.
More particularly, as specifically stated by respondent’s expert, the hypothetical salvage value of the platforms totally ignores the economics of the situation. In practical terms, the decision to reuse a platform or its components is based upon an analysis of the cost of designing and developing a new platform or component versus reusing or modifying a salvage platform or component. Thus far, such analyses have shown that the salvage of the platforms or components presently in place is not economical as compared to merely scrapping the items. Further, even respondent’s expert agreed that these platforms are designed for the particular conditions at a particular site, and that reuse would depend on finding a site with precisely the same conditions, an event not likely to occur.
We again point out that this opinion resolves certain severed issues only, and that all other issues not previously decided in this case,
We decide this issue for petitioner.
Unless otherwise indicated, all section references are to the Internal Revenue Code of 1954 as amended and in effect for the taxable years in issue, and all Rule references are to this Court’s Rules of Practice and Procedure.
In F.H.E. Oil Co. v. Commissioner, 147 F.2d 1002 (5th Cir. 1945), the Fifth Circuit Court of Appeals held that the regulation, which permitted a taxpayer to deduct expenditures for capital improvements, was contrary to law. 147 F.2d at 1005. This decision prompted Congress to adopt Concurrent Resolution 50, 79th Cong., 1st Sess., 59 Stat. 844 (1945), which recognized and approved the Treasury regulations “granting the option to deduct as expenses such intangible drilling and development costs.”
Other types of costs that are not subject to the option are intangible costs connected with equipment, facilities, and structures that are not incident to or necessary for the drilling of wells “such as structures for storing or treating oil or gas.” The costs at issue in this case do not fall within this nonoptional category.
Other issues in this docket have been decided as follows: the “Worthless Properties” issue was decided by this Court in Gulf Oil Corp. v. Commissioner, 87 T.C. 135 (1986); the “Kuwait Nationalization” issue was decided by this Court in Gulf Oil Corp. v. Commissioner, 86 T.C. 937 (1986); the “Iranian Foreign Tax Credit” issue was decided by this Court in Gulf Oil Corp. v. Commissioner, 86 T.C. 115 (1986); the “North Sea Farmout” issue was decided by this Court in Gulf Oil Corp. v. Commissioner, 84 T.C. 447 (1985).