The Commissioner determined deficiencies in the Federal income taxes due from the petitioners in the following amounts for the designated taxable years:
TYE Dec. 31— Deficiency
1969 . $3,193,299
1970 . ..2,618,218
1971 . ..1,196,609
After settlement of numerous issues determined in the Commissioner’s statutory notice of deficiency, only the taxable year ending December 31, 1971, remains in controversy. The only issue remaining for our decision is whether petitioners may deduct as intangible drilling and development costs their aliquot share of the intangible costs of drilling 17 offshore wells1 from mobile drilling rigs.
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 Sun Co., Inc., and Subsidiaries are an affiliated group of corporations whose common parent is Sun Co., Inc. (hereinafter referred to as the petitioner). Petitioner was organized under the laws of the State of Pennsylvania. Its principal place of business, at the time the petition herein was filed, was Radnor, Pa.
Petitioner or its predecessor filed consolidated Federal income tax returns on behalf of all of the petitioners for the affiliated group’s taxable years ending on December 31 of 1969, 1970, and 1971. Such returns were timely filed with the District Director of Internal Revenue in Philadelphia, Pa.
Since the year in issue, the affiliated group has been reshuffled and some of the corporations within the group have changed names. During the calendar years 1969 and 1970, and through September 30, 1971, Sun Oil Co., the parent corporation to whom the statutory notice of deficiency herein was sent (hereinafter Sun Oil Co. NJ), was a New Jersey corporation. Effective October 1, 1971, Sun Oil Co. NJ and its multiple subsidiaries reshuffled the affiliated group so that a different Sun Oil Co. (hereinafter Sun Oil Co. PA), a corporation organized under the laws of the State of Pennsylvania, became the parent holding corporation for the affiliated group. Subsequent to 1970, Sun Oil Co. PA changed its name to Sun Co., Inc. Thus, petitioner Sun Co., Inc., is successor to the parent corporation to whom the statutory notice of deficiency herein was addressed.
Some of the subsidiaries of petitioner are: Sun Oil Co. (Delaware), a Delaware corporation; Sun Oil Co. of Pennsylvania, a Pennsylvania corporation; and North Sea Sun Oil Co., Ltd. (hereinafter North Sea Sun), a Delaware corporation. At all times material to this case, petitioner and its consolidated subsidiaries (and the predecessors of petitioner and the consolidated subsidiaries of such predecessors) have been engaged in the business of acquiring and developing oil and gas properties and of marketing and transporting petroleum and petroleum products. In the course of the internal corporate restructuring which occurred in 1971, all of the oil and gas properties located in North America (including offshore interests) in which Sun Oil Co. NJ previously held an interest were transferred to Sun Oil Co. (Delaware). There being no reason for distinguishing between the various Sun entities herein, all of the Sun corporations will be dealt with as a single entity (hereinafter known as Sun) except where an entity is mentioned specifically to facilitate understanding of this opinion.
Sun Co., Inc., and its predecessors maintained their books of account and filed their consolidated Federal income tax returns on the accrual basis and on the basis of the calendar year for the years in issue.
Sun timely exercised the option to expense intangible drilling and development costs, which option is provided in section 263(c), I.R.C. 1954,2 and in section 1.612-4, Income Tax Regs. The drilling ventures of which Sun became a member timely elected, pursuant to section 761(a)(2) and the regulations thereunder, not to be treated as partnerships for purposes of the Federal income tax.
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. Sun participated in the exploration, leasing, and development of many offshore oil and gas properties during the year before us. In order to spread the costs and risks inherent in offshore mineral development, Sun would participate in these activities as part of various combines or joint ventures, two of which are relevant to this case. Sun participated in developing offshore Louisiana mineral properties as a member of a combine known as the SCAAND Group (herein sometimes referred to as SCAAND). Sun also participated in developing North Sea mineral properties via an arrangement whereby North Sea Sun held 90 percent of the operating interest in the relevant North Sea leases and North Sea Exploitation & Reserach Co. (hereinafter North Sea Exploitation) held the remaining 10 percent of the operating interest in such leases. Though the parties do not refer to this arrangement as a combine, it was effectively just such a joint venture. We will refer to that combine as the North Sea Group.
Prior to submission of bids for the right to drill in certain areas offshore Louisiana in the Gulf of Mexico, SCAAND expended substantial sums on general and detailed seismic surveys in order to gather geological and geophysical (G & G) information upon which to make the decisions regarding which areas to lease and where to drill on any blocks that they were successful in leasing. For the same reasons, the North Sea Group also expended substantial sums on G & G data prior to bidding for the rights to explore and produce certain offshore areas in the United Kingdom sector of the North Sea.
Based upon the G & G information gathered by the seismic surveys, SCAAND, in December 1970, bid and paid the following amounts for the operating interest in each of the following offshore blocks:
Number of acres in block Amount 'paid Block
5,000.00 $15,502,050.00 West Cameron 639
5,000.00 4,001,350.00 East Cameron 312
5,000.00 5,001,350.00 East Cameron 349
5,541.44 2,773,102.82 Vermilion 281 .
5,000.00 6,001,850.00 Vermilion 320 .
5,000.00 7,501,350.00 West Cameron 588
SCAAND participated in the drilling of six wells from mobile rigs on West Cameron Block 639 (such wells being designated as West Cameron 639-1 through West Cameron 639-6). Only the intangible costs of five of those wells (West Cameron 639-1 through West Cameron 639-5) remain in issue. West Cameron 639-2 was drilled as a joint unit well on an area unitized from West Cameron Block 639 and an adjoining tract, West Cameron Block 638.
SCAAND participated in the drilling of five wells from mobile rigs on East Cameron Block 312 (such wells being designated as East Cameron 312-1 through East Cameron 312-5). Only the intangible costs of drilling two of those wells (East Cameron 312-1 and East Cameron 312-2) remain in issue. East Cameron 312-1 was drilled as a joint unit well on an area unitized from East Cameron Block 312 and East Cameron Block.313. Similarly, SCAAND participated in the drilling of two joint unit wells from mobile rigs on East Cameron Block 321 on an area unitized from East Cameron Block 312 and East Cameron Block 321 (such wells being designated as East Cameron 321-1 and East Cameron 321-6). The intangible costs of drilling both of those joint unit wells remain in issue.
SCAAND drilled two wells from mobile rigs on East Cameron Block 349 (such wells being designated as East Cameron 349-1 and East Cameron 349-2). Only the intangible costs of drilling East Cameron 349-1 remain in issue.
SCAAND drilled two wells from mobile rigs on Vermilion Block 281 (such wells being designated as Vermilion 281-1 and Vermilion 281-2). Only the intangible costs of drilling Vermilion 281-1 remain in issue.
SCAAND participated in the drilling of eight wells from mobile rigs on Vermilion Block 320 (such wells being designated as Vermilion 320-1 through Vermilion 320-8). Only the intangible costs of drilling two of those wells (Vermilion 320-1 and Vermilion 320-2) remain in issue. Vermilion 320-2 was drilled as a joint unit well on an area unitized from Vermilion Block 320 and Vermilion Block 321. Similarly, SCAAND participated in the drilling of a joint unit well from a mobile rig on Vermilion Block 321 (Vermilion 321-1) on an area unitized from Vermilion Block 321 and Vermilion Block 320. The intangible costs of drilling Vermilion 321-1 remain in issue.
SCAAND participated in the drilling of two wells from mobile rigs on West Cameron Block 588 (such wells being designated as West Cameron 588-1 and West Cameron 588-2). The intangible costs of drilling these wells are not in issue. However, SCAAND also participated in the drilling of a joint unit well from a mobile rig on West Cameron Block 587 (West Cameron 587-1) on an area unitized from West Cameron Block 587, West Cameron Block 588, West Cameron Block 593, and West Cameron Block 594. The intangible costs of drilling West Cameron 587-1 remain in issue.
Meanwhile, in June of 1970, the predecessors in interest of the North Sea Group acquired, for a substantial consideration, a production license (License No. P. 096) from the Minister of Technology of the United Kingdom relating to a number of blocks located offshore in the United Kingdom sector of the North Sea. Pursuant to the terms of various agreements and conveyances, the operating interest in Production License P. 096, which included North Sea Block 22/1, was vested in the North Sea Group.
The North Sea Group drilled four wells from mobile rigs on North Sea Block 22/1 (such wells being designated North Sea 22/1-1, North Sea 22/1-1A, North Sea 22/1-2, and North Sea 22/1-2A). Inasmuch as North Sea 22/1-2 and North Sea 22/1-2A were drilled after the taxable years in question, only the intangible costs of drilling North Sea 22/1-1 and North Sea 22/1-1A remain in issue.
The following is a tabular summary of the wells drilled with mobile rigs remaining in issue:
Combine Block Wells
SCAAND. W. Cameron 639 W.C. 639-1
1W.C. 639-2
W.C. 639-3
W.C. 639-4
W.C. 639-5
E. Cameron 312 1E.C. 312-1
E.C. 312-2
1E.C. 321-1
1E.C. 321-6
E. Cameron 349 E.C. 349-1
Vermilion 281 Vermilion 281-1
Vermilion 320 Vermilion 320-1
1 Vermilion 320-2
1Vermilion 321-1
W. Cameron 588 1W.C. 587-1
North Sea Group North Sea 22/1. N.S. 22/1-1
N.S. 22/1-1A
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 developed 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.
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 commerical 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 an exploratory or wildcat well 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, which would be either a ship-shape or a semisubmersible 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 a marine riser system located on the ocean floor.
The mechanics of drilling an exploratory or wildcat well offshore are essentially the same as the mechanics of drilling such a well onshore, except for special equipment and adjustments required to compensate for water depth and the use of mobile rigs. The casing utilized offshore is basically identical to the casing utilized in drilling a well onshore.
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 located in water depths of more than 100 feet costs millions of dollars; 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. Several 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
In 1969, Sun joined with several other entities 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 (a combine), which was known as the SCAAND Group, intended to develop and produce any oil properties so acquired. The purpose of entering such a combine was to share 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 consisted primarily of the cost of conducting, or the cost of acquiring, general and detailed seismic surveys. Based upon the interpretation of such information, SCAAND prepared maps reflecting its interpretation 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 the combine did lease.
Similarly, the North Sea Group, at some time prior to drilling the wells in question, made substantial expenditures to acquire G & G information on the relevant portions of the United Kingdom sector of the North Sea. Such expenditures were made for the same purposes and with the same intent as were the G & G expeditures made by SCAAND. Based upon the G & G information so acquired, the North Sea Group prepared geological and geophysical maps reflecting its interpretation of such information and identifying structures which it considered to be potential traps for accumulations of hydrocarbons.
A. Leasing and Drilling Activities of the SCAAND Group
In December 1970, the SCAAND Group, a combine of which Sun was a member, 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 SCAAND’s bids, including the bids with respect to Blocks 639 and 588, West Cameron area — South Addition; Blocks 312, 338, 339, and 348, East Cameron area — South Addition; and Blocks 281 and 320, Vermilion area — South Addition. With regard to the activities of SCAAND, the only blocks with which we are here concerned, and the amounts bid and paid for each of those blocks, are as follows:
Number of Block acres in block Amount paid
West Cameron 639 . 5,000.00 $15,502,050.00
East Cameron 312 . 5,000.00 4,001,350.00
East Cameron 349 . 5,000.00 5,001,350.00
Vermilion 281 . 5,541.44 2,773,102.82
Vermilion 320 . 5,000.00 6,001,850.00
West Cameron 588 . 5,000.00 7,501,350.00
The members of the combine designated Sun as the operator of all of these blocks.
SCAAND participated in the drilling of six wells from mobile rigs on West Cameron Block 639 (such wells being designated as West Cameron 639-1 through West Cameron 639-6). Of those six wells, only West Cameron 639-2, which was a joint unit well, remains in issue. All six of the shafts drilled in connection with these wells were drilled in search of hydrocarbons.
SCAAND participated in the drilling of five wells from mobile rigs on East Cameron Block 312 (such wells being designated East Cameron 312-1 through East Cameron 312-5). East Cameron 312-1 is a joint unit well. In addition, SCAAND participated in the drilling of two joint unit wells from mobile rigs on East Cameron Block 321 (a block adjoining East Cameron Block 312), which wells are designated East Cameron 321-1 and East Cameron 321-6. Of these seven wells drilled in the development of East Cameron Block 312, only East Cameron 312-1, 312-2, 321-1, and 321-6 remain in issue. All seven of the shafts drilled in connection with these seven wells were drilled in search of hydrocarbons.
SCAAND drilled two wells from mobile rigs on East Cameron Block 349 (such wells being designated East Cameron 349-1 and East Cameron 349-2). Only East Cameron 349-1 remains in issue. The shafts drilled in connection with both of these wells were drilled in search of hydrocarbons.
SCAAND drilled two wells from mobile rigs on Vermilion Block 281 (such wells being designated as Vermilion 281-1 and Vermilion 281-2). Only Vermilion 281-1 remains in issue. The shafts drilled in connection with both of these wells were drilled in search of hydrocarbons.
SCAAND participated in the drilling of eight wells from mobile rigs on Vermilion Block 320 (such wells being designated as Vermilion 320-1 through Vermilion 320-8). Vermilion 320-2 is a joint unit well. In addition, SCAAND participated in the drilling of a joint unit well from a mobile rig on Vermilion Block 321, which well is designated Vermilion 321-1. Of these nine wells drilled in the development of Vermilion Block 320, only Vermilion 320-1, 320-2, and 321-1 remain in issue. The shafts drilled in connection with these nine wells were drilled in search of hydrocarbons.
SCAAND drilled two wells from mobile rigs on West Cameron Block 588 (such wells being designated as West Cameron 588-1 and West Cameron 588-2). In addition, SCAAND participated in the drilling of a joint unit well from a mobile rig on West Cameron Block 587, which well is designated West Cameron 587-1. Of these three wells, only West Cameron 587-1 remains in issue. The shafts drilled in connection with these three wells were drilled in search of hydrocarbons.
As noted, 7 of the 15 SCAAND wells that remain in issue are “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-hqle 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).
West Cameron Block .639.— The first well to be drilled with a mobile rig by SCAAND in the development of West Cameron Block 639 was West Cameron 639-2, which was spudded on February 28, 1971. After an appropriate unitization agreement was executed, this well was drilled as a joint unit well on a unit area made up of acreage from West Cameron Block 639 and West Cameron Block 638, the latter of which was owned in equal shares by Texaco, Inc., and Tenneco, Inc. The proposed total depth of the well was 10,000 feet, but the well encountered high-pressure gas at 3,956 feet and blew out. Soon thereafter, the blowout well, in effect, plugged itself. After the vicinity of the well was cleared, the well was permanently abandoned. 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. The intangible costs of drilling West Cameron 639-2 are here in issue.
The second well to be drilled with a mobile rig was West Cameron 639-1. This well was spudded on March 13, 1971, and was a dry hole. 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. West Cameron 639-1 was drilled to a total depth of 6,734 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 West Cameron 639 — 4. This well was spudded on April 1, 1971, and it eventually encountered 119 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. West Cameron 639^4 was drilled to a total depth of 5,604 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 West Cameron 639-5. This well was spudded on April 27, 1971, and it eventually encountered 28 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 thé operator, of conducting or aiding in the conduction of hydrocarbons to the surface. West Cameron 639-5 was drilled to a total depth of 8,471 feet and was then permanently plugged and abandoned. The intangible costs of drilling this well are here in issue.
The fifth well to be drilled with a mobile rig was West Cameron 639-3. This well was spudded on May 20,1971, and was a dry hole. 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. West Cameron 639-3 was drilled to a total depth of 10,177 feet and was then permanently plugged and abandoned. The intangible costs of drilling this well are here in issue.
The sixth well drilled on this block with a mobile rig, West Cameron 639-6, was spudded on March 12, 1972. This well eventually encountered 144 feet of oil and gas sands. The intangible costs of drilling this well are not here in issue.
On or about September 22, 1972, SCAAND committed itself to the fabrication and installation of a 24-well drilling and production platform on West Cameron Block 639. The estimated cost of the platform jacket and deck was $5,500,000. It was installed on West Cameron Block 639 on or about August 15, 1973. Twenty wells were drilled by Sun, as operator for SCAAND, from this platform, seven of which were dry holes. Under an agreement between Texaco, Inc., and Tenneco, Inc. (the owners of West Cameron Block 638), and the SCAAND Group, Texaco/Tenneco drilled four wells from the platform onto West Cameron Block 638, two of which were dry holes. Production from the SCAAND platform wells commenced on May 7, 1976.
East Cameron Block 312.— The first well to be drilled with a mobile rig by SCAAND in the development of East Cameron Block 312 was East Cameron 312-1. After an appropriate unitization agreement was executed, this well was drilled as a joint well on a unit area made up of acreage from East Cameron Block 312 and East Cameron Block 313, the latter of which was owned by a combine known as the Phillips Et A1 Group. East Cameron 312-1 was spudded on April 25, 1971, and was a dry hole. 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. East Cameron 312-1 was drilled to a total depth of 9,150 feet and was then permanently plugged and abandoned. The intangible costs of drilling this well are here in issue.
The second well to be drilled with a mobile rig in the development of this block was drilled on an adjoining block, East Cameron Block 321, and was designated East Cameron 321-1. After an appropriate unitization agreement was executed, this well was drilled as a joint unit well on a unit area made up of acreage from East Cameron Block 312 and East Cameron Block 321, the latter of which was owned by a combine known as the SLAM Group. East Cameron 321-1 was spudded on June 18, 1971, and it eventually encountered 33 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 hyrdocarbons and upon appropriate completion by the operator, of conducting or aiding in the conduction of hydrocarbons to the surface. East Cameron 321-1 was drilled to a total depth of 10,460 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 East Cameron 312-2. This well was spudded on August 18, 1971, and was a dry hole. 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. East Cameron 312-2 was drilled to a total depth of 7,165 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 in the development of the block was drilled, pursuant to an amendment to the above-mentioned unitization agreement between SCAAND and the SLAM Group, on East Cameron Block 321. This joint unit well, East Cameron 321-6, was spudded on September 5, 1971, and it eventually encountered 138 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. East Cameron 321-6 was drilled to a total depth of 8,030 feet and was then permanently plugged and abandoned. The intangible costs of drilling this well are here in issue.
The fifth, sixth, and seventh wells drilled with mobile rigs in the development of East Cameron Block 312 were spudded on the following dates and encountered the indicated amounts of oil and gas sands:
Feet of Well Spud date oil and gas sands
E.C. 312-3 . 8/13/72 30
E.C. 312-4 . 11/25/75 dry
E.C. 312-5 . 1/ 9/75 dry
The intangible costs of drilling those three wells are not here in issue.
SCAAND determined that the results of its drilling on and around East Cameron Block 312 did not justify further development of that block. Thus, no production platform was ordered for that block.
East Cameron Block SU9.— The first of two wells drilled with mobile rigs by SCAAND in the development of East Cameron Block 349 was East Cameron 349-1, which was spudded on April 16,1971, and was a dry hole. 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. East Cameron 349-1 was drilled to a total depth of 4,612 feet and was then permanently plugged and abandoned. The intangible costs of drilling this well are here in issue.
The second well to be drilled with a mobile rig was East Cameron 349-2. This well was spudded on May 5,1975, and was a dry hole. The intangible costs of drilling this well are not here in issue.
A drilling and production platform has been installed by SCAAND on East Cameron Block 338, which is a block owned by SCAAND which is contiguous to East Cameron Block 349. However, none of the wells drilled from that platform are bottomed under East Cameron Block 349. No platform has been installed on East Cameron Block 349.
Vermilion Block 281.— The first of two wells drilled with mobile rigs by SCAAND in the development of Vermilion Block 281 was Vermilion 281-1. This well was spudded on November 6, 1971, and was a dry hole. 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. Vermilion 281-1 was drilled to a total depth of 10,318 feet and was then permanently plugged and abandoned. The intangible costs of drilling this well are here in issue.
The second well to be drilled with a mobile rig was Vermilion 281-2. This well was spudded on April 16, 1973, and was a dry hole. The intangible costs of drilling this well are not here in issue. No platform has been installed on Vermilion Block 281.
Vermilion Block 320.— The first well to be drilled with a mobile rig by SCAAND in the development of Vermilion Block 320 was actually drilled on an adjoining block, Vermilion Block 321, and was designated Vermilion 321-1. After an appropriate unitization agreement was executed, this well was drilled as a joint unit well on a unit area made up of acreage from Vermilion Block 320 and Vermilion Block 321, the latter of which was owned by Shell Oil Co. Vermilion 321-1 was spudded on May 11, 1971, and it eventually encountered 210 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. Vermilion 321-1 was drilled to a total depth of 8,193 feet and was then permanently plugged and abandoned. The intangible costs of drilling this well are here in issue.
The second well drilled with a mobile rig in the development of Vermilion Block 320 was a joint unit well drilled under an amendment to the same unitization agreement under the authority of which Vermilion 321-1 was drilled. This well, Vermilion 320-2, was drilled using the same surface location (on Vermilion Block 321) and the same surface casing as Vermilion 321-1, but was sidetracked from that shaft so that the well bottomed under Vermilion Block 320. Vermilion 320-2 was spudded on May 29,1971, and was a dry hole. 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. Vermilion 820-2 was drilled to a total depth of 9,380 feet and was then permanently plugged and abandoned. The intangible costs of drilling this well are here in issue.
The third well drilled with a mobile rig in the development of Vermilion Block 320 was Vermilion 320-1. This well was spudded ón December 23, 1971, and it eventually encountered 68 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. Vermilion 320-1 was drilled to a total depth of 6,264 feet. This well was utilized in the drilling of another well, Vermilion 320-3, but was eventually permanently plugged and abandoned. The intangible costs of drilling Vermilion 320-1 are here in issue.
The other six wells drilled with mobile rigs in the development of Vermilion Block 320 were spudded on the following dates and encountered the indicated amounts of oil and gas sands:
Feet of Well Spud date oil and gas sands
Vermilion 320-31 . 1/ 9/72 280
Vermilion 320-4 . 2/25/72 Dry
Vermilion 320-5 . 3/27/72 Dry
Vermilion 320-6 . 4/19/72 Dry
Vermilion 320-7 . 7/26/72 183
Vermilion 320-8 . 8/18/72 79
The intangible costs of drilling these six wells are not here in issue.
Two drilling and production platforms have been installed on Vermilion Block 320. The first platform (Platform A) was approved and ordered on February 14, 1972. It was installed on Vermilion Block 320 on October 9, 1972. A total of 17 wells, including 4 dry holes, have been drilled from Platform A. Production from Platform A commenced on November 7, 1974. The second platform (Platform B) was approved on April 2, 1973, and was ordered on April 10, 1973. It was installed in February of 1974, and seven productive wells have been drilled from it. Production from Platform B commenced on May 24, 1975.
West Cameron Block 588 — The first well to be drilled with- a mobile rig by SCAAND in the development of West Cameron -Block 588 was actually drilled on an adjoining block, West Cameron Block 587, and was designated West Cameron 587-1. After an appropriate unitization agreement was executed, this well was drilled as a joint unit well on a unit area made up of acreage from West Cameron Block 588, West Cameron Block 587 (which was owned by a combine known as the POGO Et Al. Group), West Cameron Block 593 (which was owned by a combine known as the Amoco Et Al. Group), and West Cameron Block 594 (which was owned by a combine known as the Phillips Et Al. Group). West Cameron 587-1 was spudded on June 22, 1971, and it eventually encountered 102 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. West Cameron 587-1 was drilled to a total depth of 14,328 feet and was then permanently plugged and abandoned. The intangible costs of drilling this well are here in issue.
The second well drilled with a mobile rig in the development of West Cameron Block 588 was West Cameron 588-1, which was spudded on February 5, 1972, and was a dry hole. The third well drilled with a mobile rig was West Cameron 588-2, which was spudded on June 22, 1972, and was also a dry hole. The intangible costs of drilling these two wells are not here in issue. No platform has been installed on West Cameron Block 588.
B. Leasing and Drilling Activities of the North Sea Group
In June 1970, British Sun Oil Co. and North Sea Exploitation & Research Co. (North Sea Exploitation) acquired from the Minister of Technology of the United Kingdom, for a substantial consideration, a production license (License No. 096) relating to a number of blocks located offshore in the United Kingdom sector of the North Sea. Prior to 1971, pursuant to the terms of various agreements and conveyances, the operating interest in that license, which encompassed the operating interest in North Sea Block 22/1, was vested in North Sea Sun (90 percent) and North Sea Exploitation (10 percent). For convenience, we have denominated the combination of these two entities the North Sea Group. North Sea Sun was designated as the operator of North Sea Block 22/1 for the North Sea Group.
The North Sea Group drilled four wells from mobile rigs on North Sea Block 22/1 (such wells being designated as North Sea 22/1-1, 22/1-1A, 22/1-2, and 22/1-2A). Of these wells, only North Sea 22/1-1 and North Sea 22/1-1A remain in issue. All four of the shafts drilled in connection with these wells were drilled in search of hydrocarbons.
The first well to be drilled with a mobile rig by the North Sea Group in the development of North Sea Block 22/1 was North Sea 22/1-1, which was spudded on August 22, 1971. 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. The well was drilled to 1,009 feet where it was determined that the shaft was approximately 4 degrees off vertical and, therefore, such well was permanently plugged and abandoned because this was too great an angle to drill the well to its total proposed depth. The intangible costs of drilling this well are here in issue.
The second well to be drilled with a mobile rig on this block was North Sea 22/1-1A, which was spudded on September 22, 1971. 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. North Sea 22/1-1A was drilled to a depth of 9,757 feet, which was short of its proposed total depth of 14,200 feet. It developed mechanical difficulties and, therefore, never reached the formation which was the objective of the drilling. North Sea 22/1-1A was temporarily abandoned, fully cased to the total depth drilled and with a stub left on the sea floor above the mudline. The intangible costs of drilling this well are here in issue.
The third and fourth wells drilled with mobile rigs by the North Sea Group on North Sea Block 22/1 were North Sea 22/1-2 and North Sea 22/1-2A, both of which were spudded in 1973 and neither of which encountered any hydrocarbons. The intangible costs of drilling these two wells are not here in issue. No platform has been installed on North Sea Block 22/1.
V. Treatment of Items in Controversy on Income Tax Return; Commissioner’s Disallowance
Sun was, during 1971, a member of a combine, the SCAAND Group, which drilled during 1971 many wells offshore Louisiana in the Gulf of Mexico. Petitioners, on their consolidated Federal income tax return for their taxable year 1971, deducted Sun’s allocable share of SCAAND’s intangible costs of drilling 15 of those wells, 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 15 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.
Sun, via North Sea Sun, was also, during 1971, a member of a combine, the North Sea Group, which drilled during 1971 two wells in the United Kingdom sector of the North Sea. Petitioners, on their consolidated Federal income tax return for their taxable year 1971, deducted North Sea Sun’s allocable share of the North Sea Group’s intangible costs of drilling those two wells, 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 two 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.
OPINION
Petitioners are an affiliated group of corporations whose common parent is Sun Co., Inc. We refer herein to the affiliated group in the aggregate as Sun. Sun, during 1971, was a member of two drilling combines, the SCAAND Group, which was formed to acquire and develop oil and gas properties offshore Louisiana in the Gulf of Mexico, and the North Sea Group, which was formed to acquire and develop such offshore properties in the United Kingdom sector of the North Sea. These combines spent substantial sums acquiring G & G information regarding possible offshore drill sites.
Based on the G & G information obtained, SCAAND, in 1970, bid and paid the following amounts for the operating interest in each of the following offshore blocks:
Number of Block acres in block Amount paid
West Cameron 639 . 5,000.00 $15,502,050.00
East Cameron 312 . 5,000.00 4,001,350.00
East Cameron 349 . 5,000.00 5,001,350.00
Vermilion 281 . 5,541.44 2,773,102.82
Vermilion 320 . 5,000.00 6,001,850.00
West Cameron 588 . 5,000.00 7,501,350.00
SCAAND drilled six wells from mobile rigs (West Cameron 639-1 through West Cameron 639-6) on West Cameron Block 639. West Cameron 639-2 was a joint unit well. Of these six wells, only the intangible costs of drilling five of those wells (West Cameron 639-1 through West Cameron 639-5) remain in issue. SCAAND participated in the drilling of seven wells from mobile rigs on or around East Cameron Block 312. Five of these wells (East Cameron 312-1 through East Cameron 312-5) were drilled on East Cameron Block 312, one of them (East Cameron 312-1) being a joint unit well. The other two wells (East Cameron 321-1 and East Cameron 321-6) were joint unit wells drilled on East Cameron Block 321. Of these seven wells, only the intangible costs of drilling four of them (East Cameron 312-1, 312-2, 321-1, and 321-6) remain in issue. SCAAND drilled two wells from mobile rigs (East Cameron 349-1 and East Cameron 349-2) on East Cameron Block 349. Of these two wells, only the intangible costs of drilling East Cameron 349-1 remain in issue. SCAAND drilled two wells from mobile rigs (Vermilion 281-1 and Vermilion 281-2) on Vermilion Block 281. Of these two wells, only the intangible costs of drilling Vermilion 281-1 remain in issue. SCAAND participated in the drilling of nine wells from mobile rigs on or around Vermilion Block 320. Eight of these wells (Vermilion 320-1 through Vermilion 320-8) were drilled on Vermilion Block 320, one of them (Vermilion 320-2) being a joint unit well. The ninth well (Vermilion 321-1) was a joint unit well drilled on Vermilion Block 321. Of these nine wells, only the intangible costs of drilling three of them (Vermilion 320-1, 320-2, and 321-1) remain in issue. SCAAND participated in the drilling of three wells from mobile rigs on or around West Cameron Block 588. Two of these wells (West Cameron 588-1 and West Cameron 588-2) were drilled on West Cameron Block 588. The other well (West Cameron 587-1) was a joint unit well drilled on West Cameron Block 587. Of these three wells, only the intangible costs of drilling West Cameron 587-1 remain in issue.
Based upon the G & G information obtained by the North Sea Group, in 1970, its predecessors in interest paid a substantial consideration for the operating interest in North Sea Block 22/1, which operating interest devolved to the North Sea Group.
The North Sea Group drilled four wells from mobile rigs (North Sea 22/1-1, 22/1-1A, 22/1-42, and 22/1-2A) on North Sea Block 22/1. Of these four wells, only the intangible costs of drilling two of them (North Sea 22/1-1 and North Sea 22/1-1A) remain in issue.
Thus, the intangible costs of drilling 15 SCAAND wells and two North Sea Group wells remain in issue. Sun, 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 17 wells in issue as IDC and deducted it on petitioners’ consolidated Federal income tax return for the affiliated group’s taxable year 1971. Respondent contends that the costs of drilling those 17 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 taxable year 1971.
All of the shafts drilled in connection with the 17 wells remaining in issue were drilled in search of hydrocarbons. All 17 of the shafts drilled in connection with the 17 wells remaining in issue were designed and drilled in such a manner that each 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 17 wells that remain in issue.
Respondent’s position with respect to each of the wells in question is that the petitioners have not satisfied their burden of establishing that the expenditures come within the option provided by section 263(c).3 In particular, respondent’s position is that petitioners have not satisfied the requirements of section 1.612-4, Income Tax Regs.
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 return.
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).4 See F.H.E. Oil Co. v. Commissioner, 147 F.2d 1002 (5th Cir. 1945), rehearing denied 149 F.2d 238 (5th Cir. 1945), second rehearing denied 150 F.2d 857 (5th Cir. 1945). However, section 263(c) provides an exception for intangible drilling and development costs incurred by an operator in the development of oil and gas properties. Thus, the sole issue before us is whether the expenditures come within the purview of section 263(c) and section 1.612-4, Income Tax Regs. Second, the mere fact that the wells in question yielded G & G data is not controlling, for the reason that all wells yield G & G data, even those with respect to which the deductibility of intangible drilling and development costs is unquestioned. Third, in view of the rather unusual history5 of the congressional purpose underlying the optional treatment of intangible drilling and development costs, “Congress favors a liberal interpretation of the regulation.” Standard Oil Co. (Indiana) v. Commissioner, 68 T.C. 325, 345 (1977); Exxon Corp. v. United States, 212 Ct.Cl. 258, 547 F.2d 548, 555 (1976).
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 “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;6 and, finally (4) while section 616 speaks of the “development of a mine” section 1.612-4(a), Income Tax Regs, speaks of “the development of oil and gas properties.” (Emphasis added.) When the intangibles option was first provided, the development of oil and gas properties was percieved as the activity following the acquisition of those properties. Though a distinction has been made between activities before and after the decision to drill is made (Louisiana Land & Exploration Co. v. Commissioner, 7 T.C. 507 (1946), affd. 161 F.2d 842 (5th Cir. 1947), no one other than the Commissioner has ever conceived that a well could be drilled not in the development of oil and gas properties. The use of the word “development” in sections 616 and 617 is a term of art applicable only in the context in which it was enacted in those sections; i.e., hard minerals.
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 will 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 definintion 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 17 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 findings. This definition of wells avoids the concomitant administrative nightmare which would result upon the adoption of respondent’s subjective “intent to produce” test.7 Under this definition, whether a shaft is a “well” is determined on the basis of objective factual criteria.
Moreover, common sense 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 petitioners so aptly point out in their brief, would reward only the lucky, because they accidentally drill their first well on the optimum platform location, or the foolhardy, because they are 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 common sense.
We have found that each of the shafts drilled in connection with the 17 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 17 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.
Joint unit wells.
Vermilion 320-3 was drilled as a sidetrack well from the same surface location and utilizing the same surface casing as Vermilion 320-1.
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 allownace 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 USTCpar. 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 minerals 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.