1980 U.S. Tax Ct. LEXIS 51 | Tax Ct. | 1980
Lead Opinion
The Commissioner determined deficiencies in the Federal income taxes due from the petitioners in the following amounts for the designated taxable years:
Taxable year ending Deficiency
Feb. 26, 1972.$1,116,614
Dec. 29, 1973.985,904
After settlement of numerous issues determined in the Commissioner’s statutory notice of deficiency, the only issue left for us to decide is whether petitioner, the Gates Rubber Co., as a partner in a partnership which was, in turn, a partner in several other drilling partnerships, may deduct as intangible drilling and development costs its aliquot share of the intangible costs of drilling five offshore wells
FINDINGS OF FACT
Some of the facts have been stipulated. The stipulation of facts and exhibits attached thereto are incorporated herein by this reference.
I. Entities Involved in This Controversy
Petitioners, the Gates Rubber Co. & Subsidiaries, are an affiliated group of corporations whose common parent is the Gates Rubber Co. (hereinafter referred to as the petitioner). Petitioner was organized under the laws of the State of Colorado. Its principal place of business, at the time the petition herein was filed, was Denver, Colo.
Petitioner filed consolidated Federal income tax returns on behalf of all of the petitioners for the affiliated group’s taxable years ending February 26, 1972, and December 29, 1973. Such returns were filed with the Director of the Internal Revenue Service Center, Ogden, Utah, within the time period for filing such returns as extended by the Commissioner.
During the calendar years 1971 and 1973, petitioner was a partner in a limited partnership known as Hamilton Cody, Ltd. (1968) (hereinafter Cody, Ltd.). Cody, Ltd., was a partner or venturer in several partnerships or ventures involved in drilling for oil and gas offshore Louisiana in the Gulf of Mexico, offshore United Kingdom in the U.K. sector of the North Sea, and offshore Ghana in the Atlantic Ocean.
Cody, Ltd., was, during 1971, a partner in a partnership known as Hamilton Bros. Offshore Properties Co. (hereinafter Hamilton Offshore) which, during that year, participated in the drilling of wells from mobile rigs offshore Louisiana in the Gulf of Mexico.
During 1973, Cody, Ltd., was a partner in a partnership known as Hamilton Bros. Joint Venture (1972)(hereinafter Hamilton J.V.) which, during that year, also participated in the drilling of wells from mobile rigs offshore Louisiana in the Gulf of Mexico.
Each of these partnerships, Cody, Ltd., Hamilton Offshore, and Hamilton J.V., adopted the calendar year as its taxable year for Federal income tax purposes.
The three above-mentioned partnerships timely elected, pursuant to section 761(a)(2), I.R.C. 1954,
II. Origin of This Controversy
Though we will subsequently set forth the detailed facts of the drilling activities, the costs of which are the focus of this controversy, we feel that a brief summary of the facts at this juncture will be helpful to the reader.
Generally, these are the facts around which this controversy has developed. Hamilton Offshore and Hamilton J.V., through their agent Hamilton Bros. Oil Co. (hereinafter Hamilton Oil), participated in the exploration, leasing, and development of many offshore oil and gas properties during the years before us. In order to spread the costs and risks inherent in offshore mineral development, Hamilton Oil, as agent for those two partnerships, would participate in these activities as part of various combines or joint ventures. As relevant to the instant case, Hamilton Oil was a member of two distinct combines during the years before us — one known as the TransOcean Group (hereinafter sometimes referred to as TransOcean) and the other known as the Offshore Operators Group (hereinafter sometimes referred to as Offshore).
Prior to submission of bids for the right to drill in certain areas offshore Louisiana in the Gulf of Mexico, these two combines expended substantial sums on general and detailed seismic surveys in order to gather geological and geophysicial (G & G) information upon which to make their decisions regarding which areas to lease and where to drill on any blocks that they were successful in leasing.
Based upon this information, TransOcean bid and paid $38,184,350 for the rights to explore and develop Eugene Island Block 296, a 5,000-acre tract located offshore Louisiana in the Gulf of Mexico. TransOcean drilled five wells from mobile rigs on that block (such wells being numbered sequentially as Eugene Island 296-1 through Eugene Island 296-5). In addition, TransOcean participated with the lessees of two adjoining blocks, Eugene Island Block 295 and Eugene Island Block 305, in drilling three joint unit wells, Eugene Island 295-1, Eugene Island 295-4, and Eugene Island 305-1, from mobile rigs.
The other combine in which Hamilton Oil had an interest, Offshore, bid and paid $70,019,770.80 for the rights to develop South Marsh Island Block 268, a 3,237.16-acre tract located offshore Louisiana in the Gulf of Mexico. A total of eight wells were drilled on South Marsh Island Block 268, the fifth of which is designated South Marsh Island 268-5.
The only wells remaining in issue are Eugene Island 296-1, 296-3, 295-1, 305-1, and South Marsh Island 268-5.
Having presented this brief outline of the facts so as to identify the specific wells in issue, we shall, after supplying some relevant background information, provide a more detailed exposition of the facts regarding the drilling activities, the costs of which are the focus of this controversy.
III. Background Information
Exploring for and producing oil and gas offshore is similar to exploring for and producing oil and gas onshore, except for the adjustments required because the area to be explored and produced is under water. The facts that offshore oil and gas properties are under water and that the right to explore and produce such properties generally must be acquired from a government through competitive bidding have a substantial impact upon the economics of developing oil and gas offshore as contrasted with onshore.
The first step in an oil and gas operation, both offshore and onshore, is to collect and interpret geological and geophysical information to determine if the area in question contains subterranean structures which constitute potential traps for accumulations of oil or gas. Such G & G information is generally obtained through general and detailed seismic surveys. The basic technique for making such surveys is the same offshore as onshore. Based upon the results of such seismic surveys and other information, geologists and geophysicists prepare maps of the areas in question which reflect their interpretation of such information and, hopefully, identify structures which constitute potential traps for accumulations of oil or gas. However, the only way to determine whether a postulated structure contains hydrocarbons is to drill a well. Therefore, the next step in an oil and gas operation, both onshore and offshore, is to drill exploratory or “wildcat” wells to penetrate the postulated structures to determine if they contain oil or gas in commercial quantities. Only about one in 8 to 12 wildcat wells drilled, whether onshore or offshore, results in a commercial discovery.
However, some distinctions do exist between onshore and offshore drilling. Onshore, the oil and gas operator merely moves a drilling rig to the drill site, drills the well, and, if oil or gas is discovered in commercial quantities, the same drilling rig is used to complete the well for purposes of production. Offshore, such exploratory or wildcat wells are drilled from mobile rigs which are floated to the location and either anchored or set on the ocean floor in order to drill. If oil or gas is discovered, however, the well is not completed from the mobile rig. If the operator determines that it will be profitable to produce such discovered oil or gas, it is necessary to install a fixed production facility in order to complete and produce the offshore well.
Two basic types of mobile rigs are utilized to drill exploratory or wildcat wells offshore. Jack-up rigs are floated to the location of the proposed well and actually jacked up on legs to provide a stationary platform above the water level for purposes of drilling. A floating type mobile drilling rig floats to the location of the proposed well and continues to float while it is drilling the well. A floating rig is held on location solely by anchors and the drill pipe which extends from the drilling platform to the ocean floor.
Various cores, logs, tests, and samples are taken while any well is being drilled to evaluate the hydrocarbons present in the well and the commercial potential of the well. When a well reaches total depth, the operator must then decide whether it is economically feasible to complete the well as a producing oil or gas well. The basic question at this point, with respect to any type of well, is whether it is anticipated that oil and gas can be produced from the well in amounts and at a cost so that the well will produce a reasonable profit. Generally, a well drilled onshore will be completed and produced if it is determined at total depth that sufficient oil and gas can be produced from the well to cover the cost of completion, since the cost of drilling the well has been incurred whether the well is completed or not. On the other hand, in order to complete and produce a well drilled offshore, it is necessary to install some type of fixed production facility. By far the most common fixed production facility in use offshore is a fixed drilling and production platform. A fixed drilling and production platform may cost $10 million to $1 billion to construct and install; therefore, exploratory or wildcat wells are always drilled from mobile rigs to determine if sufficient quantities of oil and gas exist to justify the installation of a fixed platform and to determine the proper location of such a platform.
A well drilled from a mobile rig may be used for purposes of production to a fixed production facility in either of two ways. First, a well drilled from a mobile rig may be temporarily abandoned and later reentered and completed as a producing oil or gas well from the platform. In order to reenter a well drilled from a mobile rig from the platform, it is necessary to set the platform directly over the well and reenter the well bore from drill pipe extended from the fixed platform. A well drilled from a mobile rig may also be completed and produced to a fixed production facility through the use of a subsea completion. In a subsea completion, the well is actually completed by a mobile rig and then the well is produced to a production facility located on the ocean floor. The oil or gas produced from a subsea completion is then piped to the fixed production facility through pipes laid on the ocean floor.
When a well drilled from a mobile rig offshore reaches total depth, the operator basically has two options. First, he can permanently plug and abandon the well by installing cement plugs in the bore hole and cutting the casing below the mud line as required by Government regulations. A permanent abandonment means that the operator does not intend to utilize the well for purposes of production in the future. Second, the operator can temporarily abandon the well and thus preserve the well for possible future use for production.
There are two types of temporary abandonments, the distinction between the two being the depth of the water involved. In shallow water, the drill pipe can be reinforced by installing a caisson around the drill pipe so that the pipe can be left freestanding in the water and protruding above water level. In deeper water, however, the drill pipe cannot be left freestanding; therefore, it is necessary to cut the casing at or a few feet above the sea floor (called the mudline) so that a stub is left on the sea floor. In either type of temporary abandonment, cement plugs are installed in the bore hole for safety purposes.
A number of factors are considered in determining whether to temporarily abandon a well drilled from a mobile rig offshore so that such well may be completed in the future either by the use of subsea completions or by reentry from a fixed production platform. Some of those factors are: (1) Whether sufficient hydrocarbons are present in the particular well to justify the use of the well as a platform site or as a subsea completion; (2) whether the particular well is located at the optimum location for the fixed production platform; (3) whether the particular well is located at a spot in relation to the reservoir and to the potential platform site that it could be used as a subsea completion; (4) whether it is anticipated that installation of a production facility on the block will be economically feasible; (5) a comparison of the cost and risk to temporarily abandon the well and reenter the well from the platform against the cost and risk of drilling a replacement well from the platform; (6) a comparison of the cost and risk of temporarily abandoning the well and possibly having to permanently abandon the well in the future against the savings resulting from not having to redrill the well from the platform, taking into consideration the possibility that the particular well will not be located at the optimum site for the platform; and (7) restrictions imposed by the Government upon the type of temporary abandonment which may be used and the number of permanent structures which may be installed upon a particular block.
The primary factor in determining whether to utilize a well drilled from a mobile rig for production is the amount of hydrocarbons in the particular well and the location of that well in relation to the optimum site for the production platform, since the principal way in which a well drilled from a mobile rig is utilized in the production plan is by setting a platform over the well and reentering the well from the platform.
The determination of the optimum location for a fixed drilling and production platform is a critical decision in operating offshore. Wells drilled from a fixed platform must be deviated horizontally (slant-drilled) in order to penetrate the various producing horizons and to drain the reservoirs properly. While wells drilled from fixed platforms may be deviated at relatively high angles, the area that can be reached by wells drilled from a fixed platform is limited. As a general proposition, an operator wishes to reduce the degree of deviation of wells drilled from fixed platforms because the greater the deviation of a well the more expensive the well. Therefore, the goal in locating the fixed platform is to reach the largest amount of producible hydrocarbons by drilling wells with the lowest deviation possible.
The depth of the reserves to be produced by wells drilled from a fixed platform has a great impact upon the selection of the platform site. The platform must be located relatively close to shallow producing horizons in order for wells drilled from such a platform to penetrate such horizons. By contrast, wells can be drilled from a fixed platform to deeper producing horizons at greater distances from such platform without excessive deviation. Therefore, if the reserves to be produced by wells drilled from a fixed platform are located in relatively shallow producing horizons, it is critical to locate the platform as close as possible to such horizons.
Fabricating and installing a multiwell production platform normally takes several months. After the platform is installed, wells are drilled from the platform and, simultaneously, pipelines are laid (at least in the case of gas) to transport the production to shore. The platform wells are then completed and produced, and the production is transported to shore to be processed and marketed. As many as 6 years may elapse between the acquisition of a lease and the first delivery of production (if any) to shore. During this period, the offshore oil and gas operator, and all those who have invested in such venture, receive no return on the millions of dollars invested in the lease in the form of G & G costs, lease bonuses, drilling costs, platform costs, and pipeline costs.
With the above background information as our canvas, we can now fully illustrate the scenario which gave rise to this controversy.
IV. Detailed Facts of the Controversy
During the years in issue, Hamilton Offshore and Hamilton J.V. each designated Hamilton Oil to act as its agent to conduct business on its behalf in the Gulf of Mexico. Therefore, all activities of those two partnerships (through which Cody, Ltd., the partnership in which petitioners held an interest, invested in these drilling ventures) were undertaken by Hamilton Oil as agent or nominee with respect to the exploration, acquisition, and development of oil and gas properties in the Gulf of Mexico during the years in issue. Hamilton Oil has been in the oil and gas business since 1951.
In this agency capacity, Hamilton Oil joined with several other companies for the purposes of acquiring and evaluating G & G information with respect to areas offshore Louisiana in the Gulf of Mexico, with a view toward submitting lease bids for certain blocks based upon such information. This amalgamation of companies, also known as a combine, intended to develop and produce any oil properties acquired. The purpose of entering such combines was to share and spread among several companies the high costs and enormous risks of offshore oil and gas operations. Substantial sums were expended to obtain the above-described G & G information. Such expenditures primarily consisted of the cost of conducting, or the cost of acquiring, general and detailed seismic surveys. Based upon the interpretation of such information, the combines of which Hamilton Oil was a member (the TransOcean Group and the Offshore Operators Group) prepared maps reflecting their interpretations of the subsurface information, which maps were used for the purpose of bidding on leases and, later, for the purpose of locating the wells to be drilled on the blocks which such combines did lease.
A. Leasing and Drilling Activities of the TransOcean Group
In 1970, the TransOcean Group, a combine of which Hamilton Oil was a member both on its own account and as an agent for Hamilton Offshore and Hamilton J.Y., submitted bids for oil and gas leases on several blocks located offshore Louisiana in the Gulf of Mexico to the Bureau of Land Management, Department of Interior (the Bureau). The Bureau accepted several of TransOcean’s bids, including the bids with respect to Block 182, Vermilion area; Block 306, Eugene Island area — South Addition; Block 171, West Cameron area; and Block 296, Eugene Island area. With regard to the activities of TransOcean, the only one of these blocks with which we are here concerned is the last one listed above, Eugene Island Block 296. TransOcean bid and paid $38,184,350 for the operating interest in this 5,000-acre offshore tract.
Hamilton Oil held a 6.75-percent interest in such block including the interest held by Hamilton Oil as agent for Hamilton Offshore and Hamilton J.V. After the acquisition of Eugene Island Block 296, the TransOcean Group designated Placid Oil Co. as the operator of that block for the combine.
TransOcean drilled five wells from mobile rigs on Eugene Island Block 296. It also joined in the drilling of three wells using mobile rigs the drilling of which, though not on Eugene Island Block 296, was directly related to TransOcean’s development of that block. Of these eight wells, only four are here in issue. All eight of the shafts drilled in connection with these wells were drilled in search of hydrocarbons.
The three wells that were not drilled on Eugene Island Block 296 were “joint unit wells.” A “joint unit well” is a well drilled in an area that has been unitized. Unitization is accomplished by means of a unitization agreement, which is an “agreement under which two or more persons owning operating mineral interests agree to have the interests operated on a unified basis and further agree to share in production on a stipulated percentage or fractional basis regardless of from which interest or interests the oil or gas is produced.” Sec. 1.614 — 8(b)(6), Income Tax Regs. The general reasons for unitization have been well explicated in a leading treatise on mineral taxation:
There are a number of reasons that will cause adjoining property owners to unitize. First, more economical development and operation can be achieved through unitization, because wells can be placed in the most advantageous locations within the unitized area without regard to lease lines. Second, unitization aids conservation, because it results in development fitted to the needs of the pool of oil or gas. Third, the operating problems involved in secondary recovery methods, such as water flooding, are more readily solved if such methods are conducted on a unitized basis. [F. Burke & R. Bowhay, Income Taxation of Natural Resources, par. 17.01, pp. 1701-1702 (1980).]
A joint unit well should be contrasted with an arrangement known as a “bottom-hole contribution.” A “bottom-hole contribution” is a close cousin of the “dry-hole contribution.” In a dry-hole contribution agreement, the adjoining property owner agrees to make a contribution, either in the form of cash or other property, in the event that the well to be drilled reaches an agreed-upon depth and is found to be dry. A bottom-hole contribution agreement is made under similar circumstances, except that the contribution in cash or property is due when the well reaches a predetermined depth, regardless of whether the well is dry or productive. Dry-hole and bottom-hole contribution arrangements differ from sharing arrangements like joint unit wells because the contributor in such arrangements receives, instead of an interest in the property to which the contribution is made, G & G information that will be helpful to him in connection with his own property. F. Burke & R. Bowhay, Income Taxation of Natural Resources, par. 15.07, p. 1507 (1980).
Exxon Corp. (Exxon) was the operator of Eugene Island Block 295, the block directly west of Eugene Island Block 296. In 1971, Exxon proposed either (i) to drill a joint unit well in which TransOcean would participate on an area unitized from adjoining portions of Eugene Island Blocks 295 and 296, or (ii) to drill a well on Eugene Island Block 295 to which TransOcean would merely make a bottom-hole contribution. TransOcean chose the former option, and the two operators, Exxon and TransOcean, drilled a joint unit well, Eugene Island 295-1, on the eastern perimeter of Eugene Island Block 295. This well is one of the five wells, the intangible costs of which remain in issue.
Exxon and TransOcean later drilled from a mobile rig another joint unit well, Eugene Island 295-4, on the eastern perimeter of Eugene Island Block 295. The intangible costs of this well are not here in issue.
Chevron Oil Co. (Chevron) was the operator of Eugene Island Block 305, the block directly south of Eugene Island Block 296. After executing an appropriate unitization agreement, Chevron and TransOcean drilled a joint unit well, Eugene Island 305-1, in the extreme northwest corner of Eugene Island Block 305. This well is one of the five wells, the intangible costs of which remain in issue.
TransOcean drilled a total of five wells from mobile rigs on Eugene Island Block 296. These wells were numbered consecutively as Eugene Island 296-1 through Eugene Island 296-5. Of these five wells, only the intangible costs of drilling Eugene Island 296-1 and Eugene Island 296-3 remain in issue.
The first well to be drilled with a mobile rig by TransOcean in its development of Eugene Island Block of 296 was Eugene Island 296-1, which was spudded on or about February 10,1971. This well eventually encountered 292 feet of oil and gas sands. The shaft drilled in connection with this well was designed and drilled in such a manner that it would have been capable, upon encountering hydrocarbons and upon appropriate completion by the operator, of conducting or aiding in the conduction of hydrocarbons to the surface. Eugene Island 296-1 was drilled to a total depth of 13,677 feet and was then temporarily abandoned. The intangible costs of drilling this well are here in issue.
The second well to be drilled with a mobile rig was Eugene Island 295-1, the first joint unit well drilled with Exxon on the eastern perimeter of Eugene Island Block 295. This well was spudded on or about April 26, 1971, and it eventually encountered 712 feet of oil and gas sands. The shaft drilled in connection with this well was designed and drilled in such a manner that it would have been capable, upon encountering hydrocarbons and upon appropriate completion by the operator, of conducting or aiding in the conduction of hydrocarbons to the surface. Eugene Island 295-1 was drilled to a total depth of 9800 feet and was then permanently plugged and abandoned. The intangible costs of drilling this well are here in issue.
The third well to be drilled with a mobile rig was Eugene Island 305-1, the joint unit well drilled with Chevron in the extreme northwest corner of Eugene Island Block 305. This well was spudded on or about July 18, 1971, and it eventually encountered only 11 feet of oil and gas sands. The shaft drilled in connection with this well was designed and drilled in such a manner that it would have been capable, upon encountering hydrocarbons and upon appropriate completion by the operator, of conducting or aiding in the conduction of hydrocarbons to the surface. Eugene Island 305-1 was drilled to a total depth of 10,400 feet and was then permanently plugged and abandoned. The intangible costs of drilling this well are here in issue.
The fourth well to be drilled with a mobile rig was Eugene Island 296-2, which was spudded on or about September 14, 1971. This well eventually encountered 272 feet of oil and gas sands. The intangible costs of drilling this well are no longer in issue, respondent having conceded the deduction in his brief.
The fifth well to be drilled with a mobile rig was Eugene Island 296-3, which was spudded on or about November 11, 1971. This well eventually encountered only 86 feet of oil and gas sands. The shaft drilled in connection with this well was designed and drilled in such a manner that it would have been capable, upon encountering hydrocarbons and upon appropriate completion by the operator, of conducting or aiding in the conduction of hydrocarbons to the surface. Eugene Island 296-3 was drilled to a total depth of 9450 feet and then permanently plugged and abandoned. The intangible costs of drilling this well are here in issue.
The intangible costs of the remaining three wells drilled by TransOcean with mobile rigs on this block (which were, incidentally, all dry holes) are not here in issue.
Two 24-slot fixed platforms have been installed by TransO-cean on Eugene Island Block 296. Forty-five productive wells and two dry holes have been drilled from such platforms. TransOcean committed to the construction and installation of the first platform (Platform A) on or about September 1, 1971, just after drilling Eugene Island 305-1, based principally upon the hydrocarbons discovered by the drilling of Eugene Island 295-1. TransOcean committed to the construction and installation of the second platform (Platform B) on or about December 16, 1971, after drilling Eugene Island 296-3, based upon the hydrocarbons discovered by the drilling of Eugene Island 296-1 and Eugene Island 296-3.
B. Leasing and Drilling Activities of the Offshore Operators Group
In 1972, the Offshore Operators Group, the second combine of which Hamilton Oil was a member both on its own account and as an agent for Hamilton Offshore and Hamilton J.V., submitted to the Bureau bids for oil and gas leases on several blocks located offshore Louisiana in the Gulf of Mexico. The Bureau accepted several of Offshore’s bids, including the bids with respect to Blocks 268 and 269, South Marsh Island area — north addition. With regard to Offshore’s activities, the only one of these blocks with which we are here concerned is South Marsh Island Block 268. Offshore bid and paid $70,019,770.80 for the operating interest in this 3,237.16-acre offshore tract. Hamilton Oil held a 10-percent interest in such block including the interest held by Hamilton Oil as agent for Hamilton Offshore and Hamilton J.V. After the acquisition of South Marsh Island Block 268, the Offshore Operators Group designated Placid Oil Co. as the operator of that block for the combine.
Offshore drilled eight wells from mobile rigs on South Marsh Island Block 268, such wells being numbered consecutively South Marsh Island 268-1 through South Marsh Island 268-8. It also drilled two such wells on South Marsh Island Block 281 (South Marsh Island 281-1 and 281-2), which block was later acquired. The intangible costs of drilling only one of these wells, South Marsh Island 268-5, remain in issue. All 10 of the shafts drilled in connection with these wells were drilled in search of hydrocarbons.
Four wells were drilled from mobile rigs by Offshore on South Marsh Island Block 268 prior to the drilling of South Marsh Island 268-5, which was spudded on or about November 14,1973, from a mobile drilling rig. This well eventually encountered 123 feet of oil and gas sands. The shaft drilled in connection with this well was designed and drilled in such a manner that it would have been capable, upon encountering hydrocarbons and upon appropriate completion by the operator, of conducting or aiding in the conduction of hydrocarbons to the surface. South Marsh Island 268-5 was drilled to a total depth of 14,910 feet and then permanently plugged and abandoned. The intangible costs of drilling this well, along with the costs of drilling the four wells drilled on or around Eugene Island Block 296 which have been previously identified, are the only items remaining in issue in this controversy.
After drilling South Marsh Island 268-5, Offshore drilled two wells from mobile rigs on South Marsh Island Block 281, the block directly south of South Marsh Island Block 268, which block they later acquired. Offshore then returned to South Marsh Island Block 268 and drilled three more wells from mobile rigs. None of the intangible costs of the wells drilled after the drilling of South Marsh Island 268-5 are here in issue.
Two mulitwell platforms have been installed by Offshore on South Marsh Island Block 268 and one multiwell platform has been installed in the north sector of South Marsh Island Block 281. Twenty-one productive wells and two dry holes have been drilled on South Marsh Island Block 268 from the two platforms located thereon, and 11 productive wells have been drilled on South Marsh Island Block 281 from the platform that has been placed thereon. Offshore committed to the construction and installation of the first platform to be installed on South Marsh Island Block 268 (Platform A) on or about July 1973 after some of the results from the drilling of South Marsh Island 268-3 had become known. Offshore committed to the construction and installation of the platform which was installed on South Marsh Island Block 281 (Platform C) in mid-January 1974 during the drilling of South Marsh Island 268-5. At the time that South Marsh Island 268-5 was being drilled, and that Platform C was ordered, Offshore did not own the drilling rights to South Marsh Island Block 281. Therefore, the platform was actually ordered for installation on South Marsh Island Block 268, but was subsequently installed on South Marsh Island Block 281 after Offshore acquired the rights to that block. Offshore committed to the construction and installation of the second platform to be installed on South Marsh Island Block 268 (Platform D) on or about mid-November 1974 during the drilling of the second well to be drilled on South Marsh Island Block 281 (South Marsh Island 281-2).
V. Treatment of the Items in Controversy on Income Tax Return; Commissioner’s Disallowance
Hamilton Offshore and Hamilton J.V. were, via their agent Hamilton Oil, partners in the TransOcean Group. Cody, Ltd., was a partner in both Hamilton Offshore and Hamilton J.V. Petitioner was a limited partner in Cody, Ltd. Through this investment chain, petitioners, on their consolidated Federal income tax return for their taxable year ending February 26, 1972, deducted petitioner’s allocable share of TransOcean’s intangible costs of drilling Eugene Island 296-1, 296-3, 295-1, and 305-1, characterizing such costs as intangible drilling and development costs deductible under section 263(c). The amount of the intangible drilling costs is not in dispute. The Commissioner, however, denies that the costs of drilling those four wells come within the definition of intangible drilling and development costs found in section 1.612-4, Income Tax Regs., and, therefore, disallowed petitioners’ deduction of those costs.
Hamilton Offshore and Hamilton J.V. were also, via their agent Hamilton Oil, partners in the Offshore Operators Group. Since Cody, Ltd., was a partner in both Hamilton Offshore and Hamilton J.V., and since petitioner was a limited partner in Cody, Ltd., petitioners, on their consolidated Federal income tax return for their taxable year ending December 29, 1973, deducted petitioner’s allocable share of Offshore’s intangible costs of drilling South Marsh Island 268-5, characterizing such costs as intangible drilling and development costs deductible under section 263(c). The amount of the drilling costs is not in dispute. The Commissioner, however, denies that the costs of drilling that well come within the definition of intangible drilling and development costs found in section 1.612-4:, Income Tax Regs., and, therefore, disallowed petitioners’ deduction of those costs.
OPINION
Petitioners are an affiliated group of corporations whose common parent is the Gates Rubber Co. (petitioner). Petitioner indirectly invested, via a chain of partnerships and drilling ventures, in two drilling combines, TransOcean and Offshore. These combines spent substantial sums acquiring G & G information regarding possible drillsites offshore Louisiana in the Gulf of Mexico.
Based on the G & G information obtained, TransOcean, in 1970, bid and paid $38,184,350 for the operating interest in a 5,000-acre offshore tract known as Eugene Island Block 296. In 1971, TransOcean drilled a total of eight wells from mobile rigs on or around Eugene Island Block 296. The three wells not drilled on Eugene Island Block 296 were joint unit wells drilled with the owners of adjoining offshore tracts. The five wells drilled on Eugene Island Block 296 were numbered Eugene Island 296-1 through Eugene Island 296-5. The joint unit wells drilled are Eugene Island 295-1, Eugene Island 305-1, and Eugene Island 295-4. Of these eight wells, only four remain in issue: Eugene Island 296-1, Eugene Island 296-3, Eugene Island 295-1, and Eugene Island 305-1. Petitioner, having timely made the appropriate election to currently deduct intangible drilling and development costs (IDC), characterized its allocable share of the costs of drilling the four wells in issue as IDC and deducted it on petitioners’ consolidated Federal income tax return for the affiliated group’s taxable year ending February 26, 1972. Respondent contends that the costs of drilling those wells cannot correctly be characterized under section 263(c) and section 1.612-4, Income Tax Regs., as IDC and, therefore, determined deficiencies in petitioners’ Federal income tax for that taxable year.
Based upon the same G & G information mentioned above, Offshore, in 1972, bid and paid $70,019,770.80 for the operating interest in a 3,237.16-acre offshore tract known as South Marsh Island Block 268. During 1973-75, Offshore drilled a total of 10 wells from mobile rigs on or around South Marsh Island Block 268. The two wells not drilled on South Marsh Island Block 268 (South Marsh Island 281-1 and 281-2) were drilled on South Marsh Island Block 281, the block directly south of South Marsh Island Block 268, which block Offshore later acquired. The eight wells drilled on South Marsh Island Block 268 were numbered South Marsh Island 268-1 through 268-8. Of these 10 wells, only one remains in issue: South Marsh Island 268-5, which was drilled in 1973.
Petitioner, having timely made the appropriate election to currently deduct IDC, characterized its allocable share of the costs of drilling the well in issue as IDC and deducted it on petitioners’ consolidated Federal income tax return for the affiliated group’s taxable year ending December 29, 1973. Respondent contends that the costs of drilling that well cannot be correctly characterized as IDC and, therefore, determined deficiencies in petitioners’ Federal income tax for that taxable year.
All five of the shafts drilled in connection with the five wells remaining in issue were drilled in search of hydrocarbons. All five of the shafts drilled in connection with the five wells remaining in issue were designed and drilled in such a manner that each one of them would have been capable, upon encountering hydrocarbons and upon appropriate completion by the operator, of conducting or aiding in the conduction of hydrocarbons to the surface.
There is no dispute over the amounts of the claimed IDC, nor is there any contention by respondent that such claimed IDC, if we ultimately so characterize the drilling costs in issue, were deducted in the wrong taxable year. The only dispute between the parties is over the characterization as IDC of the relevant intangible costs of drilling the five wells that remain in issue.
Respondent’s position with respect to each of the wells in question is that petitioner has not satisfied its burden of establishing that the expenditures come within the option provided by section 263(c),
For the reasons expressed below, we hold that the intangible costs incurred in drilling each of the wells in question constitute intangible drilling and development costs within the meaning of the regulations and were properly deducted on petitioners’ consolidated Federal income tax returns.
The resolution of the issue before us requires an interpretation of section 1.612-4, Income Tax Regs., which provides in pertinent part as follows:
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—
(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. * * *
At the outset, before proceeding to an analysis of the language of the regulations and the opposing positions of the parties, certain observations are in order. First, those cases dealing with the question of whether certain expenditures are capital in nature are useless in deciding the issue before us. It is undisputed that all of the expenses in question are capital expenditures described in section 263(a).
Respondent’s position regarding the deductibility of intangible drilling and development costs is twofold. First, he contends that, as a general rule, only the intangible costs of drilling those shafts drilled after a taxpayer has decided to commence preparing to produce a reservoir fall within the definition of IDC. Second, he would allow as IDC the intangible costs of drilling “wells,” even if they are drilled prior to the time the taxpayer decides to commence preparing to produce a reservoir. This latter allowance is functionally limited, however, by respondent’s restrictive definition of what is a “well” for these purposes, i.e., that a “well” is a shaft drilled with the intention of producing from that shaft any hydrocarbons encountered by that shaft in commercial quantities. Respondent would deny that the costs of drilling a shaft not meeting his definition of a “well” qualify for the intangibles option.
Though we will now analyze and deal with each strand of respondent’s theory, we note that we find little, if any, distinction between the theories presented by respondent in this case and those he presented and which we rejected in our recent decision, Standard Oil Co. (Indiana) v. Commissioner, 68 T.C. 325 (1977).
Respondent contends that, as a general rule, the intangible costs of drilling only those shafts drilled after a taxpayer has decided to commence preparing to produce a reservoir fall within the definition of IDC. He derives this position by initially focusing on the operative language in the first sentence of section 1.612-4(a), Income Tax Regs., which says, “intangible drilling and development costs incurred by an operator * * * in the development of oil and gas properties may at his option be chargeable to capital or to expense.” (Emphasis added.) Thus, respondent concludes that only those intangible costs incurred in the development of oil and gas properties fall within the definition of IDC. Building on that assumption, respondent then seeks to build a case for the proposition that “development” occurs only after a decision to produce from a particular reservoir has been made. Based on that tenet, he would classify some wells as “exploratory” and some as “developmental,” the distinction depending on whether such wells were drilled before or after a decision to produce from a certain reservoir had been made, and would deny the IDC option with regard to the intangible costs of drilling the so-called “exploratory” wells. We could not be more convinced that this chain of reasoning and its resulting effect are erroneous.
The weak link in respondent’s theory is the conclusion that “development” occurs only after a decision to produce from a particular reservoir has been made. He bases this theory on an inapposite analogy to the hard minerals income tax provisions. Sections 616 and 617 specifically define and set forth the treatment of development and exploration expenditures incurred in extracting hard minerals. However, we find these provisions dealing with hard minerals of little relevance in our consideration of the intangibles option for oil and gas development for the following reasons: (1) The option to deduct IDC incurred in the development of oil and gas properties has existed in some form since 1917, while the predecessors of both section 616 and section 617 were not enacted until 1951; (2) the obvious functional differences between hard mineral mining and hydrocarbon drilling show that, although it is easy to establish a clear line of demarcation between exploring for hard minerals and developing mines, that line is undrawable in the oil and gas context; (3) the specific language of section 616 and section 617 exclude their application to oil and gas wells;
Moreover, not only is respondent’s use of the word “development” erroneous from a technical standpoint, it clearly would thwart the whole policy undergirding the intangibles option. As we painstakingly set forth on pages 346-351 of our opinion in the Standard Oil case, the IDC option was enacted to encourage risk-taking. Respondent’s theory would deny, in offshore wells, the IDC deduction to the very entrepreneurs for whom it was enacted — those investors who take the enormous risks entailed in drilling the wildcat wells — and would allow the IDC deduction only for those low-risk wells drilled after the wildcatters had found the oil or gas. The weakness of this position is readily apparent. The taking of risks has always been inextricably related to the availability of the IDC option. Standard Oil Co. (Indiana) v. Commissioner, supra at 350; Haass v. Commissioner, 55 T.C. 43, 50 (1970). In Standard Oil we dealt at length with why respondent’s theory would negate, in offshore wells, the encouragement of risk-taking which is the raison d’etre of the IDC option; therefore, we will not restate it in full again. However, we would reiterate: (1) That respondent’s analogy to the hard minerals provisions is inapposite; (2) that there is no distinction, for purposes of the intangibles election, between exploratory drilling and development drilling; (3) that the dividing line between “exploratory” work (G & G expenditures) which must be capitalized and “development” activities coming within the IDC option is the point at which preparations for drilling begin (Louisiana Land & Exploration Co. v. Commissioner, 7 T.C. 507 (1946), affd. 161 F.2d 842 (5th Cir. 1947)), and not, as respondent contends, at the point at which the decision to produce is made; and, therefore, (4) that “the development of oil and gas properties” begins when the decision to drill particular wells has been made.
The other strand of respondent’s argument goes like this: even if a well cannot meet respondent’s criteria of a “development” well, which we rejected above, the costs of drilling such a well would, nevertheless, come within the IDC option by force of this part of section 1.612-4(a), Income Tax Regs.:
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,
[Emphasis added.]
The only catch is that respondent would define “wells” as only those shafts drilled with the intent to produce hydrocarbons if encountered in the shaft in commercial quantities. This argument is merely a restatement in different form of respondent’s argument in Standard Oil where, instead of using the “intent” test to limit the definition of the word “wells,” he sought to tack the intent test onto the general requirements of section 1.612-4, Income Tax Regs. We rejected the intent test in Standard Oil, but found, as facts, that each of the wells in issue in that case was drilled with the intent to produce such well if it were economically feasible. The Commissioner had the opportunity to appeal our decision in that case to test our holding that intent should not control. For reasons not known to us, he did not pursue his right of appeal. Because we rejected the intent test in Standard Oil, and we again reject it here, we decline to make findings of fact which are irrelevant, i.e., whether petitioner intended to produce hydrocarbons from the five wells in issue. Accord, Newark Morning Ledger Co. v. United States, 416 F. Supp. 689 (D. N.J. 1975), affd. 539 F.2d 929 (3d Cir. 1976); Moore v. United States, 449 F. Supp. 163 (N.D. Tex. 1978). We will not permit the Commissioner to engraft the “intent” test onto the definition of the word “wells.” However, because of the way in which respondent has presented this argument, we perceive a need to define the term “wells” for purposes of the intangibles option.
For purposes of section 263(c), and section 1.612-4, Income Tax Regs., a “well” is a shaft drilled in search of hydrocarbons, which shaft is designed and drilled in such a manner that it would be capable, upon encountering hydrocarbons and upon appropriate completion of the shaft by the operator, of conducting or aiding in the conduction of hydrocarbons to the surface. This definition of wells excludes shafts, such as core drillings, which, because of their design or the manner in which they are drilled, would not be capable of conducting or aiding in the conduction of hydrocarbons to the surface, but, rather, are capable solely of yielding G & G information. If an appropriately designed shaft is drilled in search of hydrocarbons, it is a “well” regardless of the presence or absence of an intent to produce hydrocarbons from that particular shaft. We reiterate our clear-cut holding in the Standard Oil case on the matter of intent: “The answer to respondent’s contention is simply that the regulations contain no requirement of an intention to complete and produce a particular well.” (68 T.C. at 351, 352; fn. ref. omitted.)
Inasmuch as our holding as to the definition of “wells” requires no finding with regard to any person’s intent, we have made no such finding. This definition of “wells” avoids the concomitant administrative nightmare which would result upon the adoption of respondent’s subjective “intent to produce” test.
Moreover, commonsense buttresses our conclusion that it would be a mistake to graft respondent’s subjective intent test onto the definition of a well for IDC purposes. Respondent’s theory would classify a shaft as a well only if it were drilled with the intent to produce from that shaft hydrocarbons encountered in commercial quantities. Thus, for the first well drilled in an offshore block (which well, when considering risk, is most deserving of the benefits of the intangibles option), the intangibles option would be available only if it were drilled with the intent to produce, out of that well, oil or gas if found in commercial quantities. Such an interpretation, as petitioner so aptly points out in its brief, would reward only the lucky, because he accidentally drilled his first well on the optimum platform location, or the foolhardy, because he is going to produce out of that first well regardless of whether it is or is not the most efficient and economical location for the platform. Therefore, our holding on this issue in both Standard Oil and herein is not only what we perceive to be a correct interpretation of the law, but is also a decision based upon commonsense.
We have found that each of the shafts drilled in connection with the five wells remaining in issue was drilled in search of hydrocarbons, and that those shafts were designed and drilled in such a manner that each one of them would have been capable, upon encountering hydrocarbons and upon appropriate completion of such shafts by the operator, of conducting or aiding in the conduction of hydrocarbons to the surface. Such shafts were, therefore, “wells” for purposes of section 263(c), and section 1.612-4, Income Tax Regs.
For the reasons stated herein and in Standard Oil Co. (Indiana) v. Commissioner, 68 T.C. 325 (1977), we hold that the intangible costs incurred in drilling the five wells in question constitute intangible drilling and development costs within the meaning of section 263(c), and section 1.612-4, Income Tax Regs., and were properly deducted on petitioners’ consolidated Federal income tax returns. Multiple concessions having been made,
Decision will be entered under Rule 155.
The parties have jousted on brief as to whether the wells in issue should be referred to as “wells” or “boreholes.” Without prejudging the issue of whether these wells are “wells” for purposes of the intangibles deduction, nevertheless, we are constrained by tradition and our knowledge of the conventional vocabulary of the oil and gas industry to use the word “well” when we are speaking generally of shafts drilled in the context of hydrocarbon development and production.
All section references are to the Internal Revenue Code of 1954 as amended.
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 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.
SEC. 263. CAPITAL EXPENDITURES.
(a) General Rule. — No deduction shall be allowed for—
(1) Any amount paid out for new buildings or for permanent improvements or better-ments made to increase the value of any property or estate. This paragraph shall not apply to—
(A) expenditures for the development of mines or deposits deductible under section 616,
(B) research and experimental expenditures deductible under section 174,
(C) soil and water conservation expenditures deductible under section 175,
(D) expenditures by farmers for fertilizer, etc., deductible under section 180, or
(E) expenditures by farmers for clearing land deductible under section 182.
(2) Any amount expended in restoring property or in making good the exhaustion thereof for which an allowance is or has been made.
The option to deduct intangible drilling and development costs has been available to oil and gas operators since 1917. It existed as a regulation unsupported by specific statutory authority until 1954. After the regulations were held invalid in F.H.E. Oil Co. v. Commissioner, 147 F.2d 1002 (5th Cir. 1945), House Concurrent Resolution 50 was promptly adopted declaring that the regulations had been recognized and approved by Congress. In 1954, sec. 263(c) was enacted. Exxon Corp. v. United States, 212 Ct.Cl. 258, 547 F.2d 548, 553-554 (1976); P. Fielder, “The Option to Deduct Intangible Drilling and Development Costs,” 33 Tex. L. Rev. 825 (1955); H. Mahin, “Deduction for Intangibles,” 2d Oil & Gas Inst. 367 (1951).
The intangible drilling regulations were discussed in a hard minerals context in Amherst Coal Co. v. United States, 295 F. Supp. 421 (S.D. W.Va. 1969), affd. per curiam in an unpublished opinion (4th Cir. 1971, 27 AFTR 2d 71-460, 71-1 USTC par. 9223), but only to aid the court in distinguishing between depletable and depreciable assets, which distinction is an inquiry common to both the hard minerals and the oil and gas fields. That judicial usage entailed an application of the IDC concepts in the hard minerals context and not, as respondent seeks to do, an application of hard mineral concepts in the IDC context.
A difficult question rears its ugly head when we contemplate how an “intent to produce” test would be applied; specifically, whose intent would be controlling? Each member of a combine may have a differing intent, and the intention of the majority may be different from the intent of the taxpayer under inquiry. Having puzzled in the abstract over the possible solutions to that quandary, we see no need to speculate on whose intent would control and willingly eliminate such considerations by our holdings herein and in the Standard Oil case.