
    Standard Oil Company (Indiana), Petitioner v. Commissioner of Internal Revenue, Respondent
    Docket No. 9184-73.
    Filed June 7, 1977.
    
      Lee I. Park, Glenn L. Archer, Jr., Charles M. Bruce, Richard M. Roberts, and Charles W. Nyquist, for the petitioner.
    
      Thomas J. Miller and J. Michael Adcock, for the respondent.
   Goffe, Judge:

The Commissioner determined deficiencies in petitioner’s Federal income tax as follows:

Year Deficiency

1967. $10,065,739.20

1968. 8,533,941.34

1969. 30,532,036.79

Most of the numerous issues raised by the pleadings have been settled by the parties. Accordingly, the sole issue for decision is whether expenses incurred by three of petitioner’s subsidiaries in connection with the drilling of offshore wells with mobile rigs constitute intangible drilling and development costs within the meaning of section 263(c), I.R.C. 1954, and section 1.612-4, Income Tax Regs.

FINDINGS OF FACT

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

Standard Oil Co. (Indiana), the petitioner herein, had its principal office and place of business in Chicago, Ill., at the time it filed its petition in this proceeding. Petitioner, as the parent corporation, and the affiliated corporations listed in the notice of deficiency, filed consolidated Federal income tax returns for the taxable years 1967, 1968, and 1969 with the District Director of Internal Revenue at Chicago, Ill.

At all relevant times the books of such corporations were maintained on the accrual basis of accounting. For book purposes, depletion of producing properties and amortization of intangible drilling and development costs which apply to productive wells are computed on the unit-of-production method, based on estimated recoverable oil and gas reserves. For income tax purposes, all intangible drilling and development costs are deducted when incurred.

During the years 1967,1968, and 1969 all of the outstanding stock of Amoco Production was owned directly by petitioner; all of the outstanding stock of Amoco U.K. and Amoco Trinidad was owned directly or through subsidiaries by petitioner. During this period petitioner and its subsidiaries were engaged in the business of acquiring, exploring, and developing oil and gas properties and producing, refining, marketing, and transporting petroleum and petroleum products.

During the years 1967 through 1969 Amoco Production drilled four wells with mobile drilling rigs in blocks 89, 205, and 219 located in the offshore waters of Louisiana; Amoco U.K. drilled nine such wells in blocks 49/18, 49/23, 49/27, and 22/18 in the U.K. portion of the North Sea; and Amoco Trinidad drilled eight such wells in the OPR and SEG areas off the coast of Trinidad. Each of petitioner’s subsidiaries owned a working interest in the oil and gas properties in which its wells were located.

Prior to the drilling of these wells, substantial expenditures were incurred to obtain geological and geophysical information (G & G) relating to the subsurface configurations underlying the offshore waters in which the wells were located. Such expenditures consisted for the most part of the costs of reconnaissance and detailed surveys of the type described in I.T. 4006, 1950-1 C.B. 48. The surveys conducted consisted mainly of seismic surveys. An offshore seismic survey is conducted by pulling a cable containing geophones through the water. A second boat is placed at a particular position along the cable; as both boats progress in a straight line, numerous shots are fired and the resulting acoustic waves travel through the earth and are reflected back to be recorded on the geophones. A reconnaissance-type survey produces a basis for regional geophysical interpretation which allows readings of larger anticlinal and piercement-type features or other major discrepancies in the subsurface configuration. Based upon the information obtained from the seismic surveys, or otherwise, seismic maps were made which were used to determine the location of the wells. Although the basic technique for conducting such surveys is the same offshore as onshore, the offshore surveys are less expensive due to the fact that the process is faster offshore and there are no expenses for permits or options.

Geological and geophysical information provides only a general identification of areas which may have the proper configuration for the accumulation of hydrocarbons. The only way of confirming whether hydrocarbons are actually present in a postulated structure, or even to confirm the existence of the structure, is to drill.' Less than 1 in 10 postulated structures in the United States is found to contain hydrocarbons.

Offshore wells can be drilled from mobile drilling rigs; however, unless a subsea completion system can be utilized, offshore wells can be produced only by installing very expensive stationary production platforms which are attached to the ocean floor with the upper portion extending above the surface of the water. In Trinidad the total cost of a platform, the platform wells, and production facilities may be as high as $40 million or $50 million. Due to the tremendous costs of production in offshore waters, once the existence of hydrocarbons in a postulated structure has been determined, additional information generally must be obtained by drilling other wells from mobile rigs before the economic decision to set a platform can be made. It is necessary to discover more oil or gas offshore to justify the necessary production expenditures than would be required under similar circumstances onshore. If a well is drilled onshore and sufficient hydrocarbons are discovered, there are few instances in which the well will not be produced. When hydrocarbons are encountered in the drilling of offshore wells with mobile rigs, whether those hydrocarbons will be produced depends upon the ultimate economics of developing the property, taking into account the costs of facilities, including the costs of fabricating and locating multiwell platforms.

Due to the high cost of locating and building permanent drilling and production platforms, petitioner’s subsidiaries followed the practice of drilling its initial wells in unproven offshore areas from mobile drilling rigs. The first exploratory well was ordinarily drilled to the indicated high point of a postulated hydrocarbon-bearing structure, as indicated by seismic interpretation. If oil or gas was discovered, the well was tested and then temporarily abandoned, after which the rig was moved to another location to drill a confirmation or delineation well. If oil or gas was again discovered, the well would also be tested and then temporarily abandoned until the oil and gas reservoir was approximately delineated with respect to both its areal extent and the amount of the recoverable oil and gas in place.

The wells drilled from mobile rigs confirmed the existence or nonexistence of hydrocarbons and gave petitioner’s subsidiaries information regarding the size and configuration of the reservoir, the amount and quality of recoverable oil or gas in place, and whether the well could be utilized as a platform site or completed by installing a subsea Christmas tree. This information was necessary before a decision could be made as to whether to install a permanent drilling and production platform, as well as to the size, location, and number of platforms to be used.

With the exception of two dry holes drilled in the offshore waters of Trinidad, each of the wells previously mentioned found potentially producible hydrocarbons. Production casing was authorized to the total depth of each such well and installed to the hydrocarbon-bearing zones. This was done in order to conduct a more extensive production testing program and also to make it possible to utilize the well in the future for either a subsea completion or a tieback to a platform. It is possible, to conduct a drill stem test, trap test, or production test without production casing; however, if more than one production zone is open, it cannot be ascertained from which zone production is coming and the results will not be representative of what would actually occur if the well were perforated through the production casing. Each of the wells which found potentially producible hydrocarbons was left in a condition for reentry to hydrocarbon-bearing zones with a subsea suspension of all casing strings, including production casing, so that the well could be utilized in the future for either a subsea completion or tieback to a platform.

In order to reenter a suspended well from a permanent platform, the well must be located; the platform must be placed almost directly over the hole; the plug must be drilled out; the well must be cleaned; and the casing sometimes must be perforated, all of which involve additional costs and risks. If the casing of a well has been cut below the mudline, additional costs must be incurred.

Each of the wells drilled from mobile rigs by petitioner’s subsidiaries in the areas previously mentioned during the years 1967 through 1969 was drilled at a location considered to be a potential platform site. Each of the wells was drilled to ascertain the existence, type, quality, and quantity of hydrocarbons and to be completed as a producing well if economically feasible to do so. None of the wells was drilled solely for information. The drilling of the wells was an integral and necessary part of the development of the respective oil and gas properties.

Construction time for platforms required from 12 to 15 months prior to setting or installation of the platform. Eight drilling platforms have been installed in the three blocks previously mentioned or in adjacent blocks owned by the same parties in the Gulf of Mexico, nine drilling platforms have been installed in the four blocks in the North Sea, and six drilling platforms have been installed in the OPR area in Trinidad. Eighty-two platform wells have been completed from such platforms in the Gulf of Mexico, 94 from such platforms in the North Sea, and 77 from such platforms in the OPR area in Trinidad. Six of the Gulf platforms and three of the North Sea platforms were set over and used to complete for production wells previously drilled from mobile rigs. An unsuccessful attempt was máde to set another North Sea platform over a well previously drilled from a mobile rig and an unsuccessful attempt was made to set a Trinidad platform over a well previously drilled from a mobile rig. Since 1962, 42 wells drilled by Amoco Production in the Gulf of Mexico have found potentially producible hydrocarbons and 14 have had platforms set over them and have been reentered from the platforms.

Prior to and during the years 1967 through 1969 the Research Department of Amoco Production was actively studying the feasibility of using subsea completion systems. The results of its study were made known to petitioner’s other affiliates. A subsea completion system allows the wellhead assembly equipment to be located on the ocean floor and uses flowlines to carry the oil and gas to a collection point — either a platform or a mooring device. This device permits a well drilled with a mobile rig to be produced without the need of placing a permanent production platform above it or drilling a directional well from a platform to the hydrocarbon-bearing zones located by the well. The state of technology with respect to such systems during the years 1967 through 1969 was for the most part experimental and limited. Most completions involved the use of remote control adaptations and divers. There was little data available to the industry at that time regarding how these systems performed. After a joint effort by Amoco Production and Lockheed to evaluate the effectiveness of subsea completion systems, it was concluded that such systems provided a practical and workable approach to the production of wells from the ocean floor. In 1964 a recommendation to make a subsea completion was made with respect to well No. 2, West Delta Block 90. Such recommendation was approved by the general office of Amoco Production. However, its 25-percent partner in this block concluded that it was not economically feasible to make a subsea completion and did not wish to undertake it. As a result, the subsea completion was never made. As of July 1975, 252 subsea completion systems had been installed or were planned for installation throughout the world. Many of these were installed during the 1960’s. As of September 1976 neither petitioner nor any of its affiliates had a subsea completion system in operation in offshore waters. However, at that time the installation of a subsea completion system had been authorized by Amoco Production for installation in the Gulf of Mexico. At such time petitioner and its subsidiaries were engaged in a major engineering study aimed at evaluating, identifying, and testing a preferred subsea completion system for development and production of two specific oil fields in the North Sea.

Amoco Production

During the taxable years 1967 through 1969 Amoco Production was engaged in the business of acquiring, exploring, and developing oil and gas properties, principally in the United States and in offshore United States waters, and producing and selling its share of the oil and gas from such properties. Prior to 1967, Amoco Production, as operator, had drilled three wells on OCS-G-1088 lease, West Delta Block 89; Texaco, as operator, had drilled three wells on OCS-0805 lease, Eugene Island Block 205; and Amoco Production, as operator, had drilled four wells on OCS-0829 lease, Ship Shoal Block 219. Each of the blocks is located in the Gulf of Mexico off the coast of Louisiana. During 1967 and 1968, Amoco Production and Texaco drilled four wells from mobile rigs on such leases. Amoco Production incurred intangible costs in connection therewith as follows:

The following is a schedule showing, with respect to each of the four wells drilled in 1967 and 1968 and for the previously drilled wells on the same leases, the spud date, the date drilling operations were completed, whether any potentially producible hydrocarbon-bearing zone was found, and whether the well was left in a condition for reentry to the hydrocarbon-bearing zone:

Property name and well number Spud date Date drilling operations completed Potentially Producible hydrocarbon-bearing Left in condition for reentry?

OCS-G-1088 West

Delta Block 89:

Well No. 1. 10/7/62 11/12/62 No No

Well No. 2. 2/27/63 3/23/63 No No

Well No. 3. 3/17/64 4/23/64 Yes Yes

Well No. 4. 12/13/66 1/19/67 No No

Well No. 5. 1/18/68 3/13/68 Yes Yes

OCS-0805 Eugene

Island Block

205:

Well No. 1. 6/19/61 7/8/61 Yes Yes

Well No. 2. 7/10/61 7/23/61 No No

Well No. 3. 2/22/66 3/25/66 Yes Yes

Well No. 4. 1/23/67 2/14/67 Yes Yes

Well No. 5. 3/14/67 4/8/67 Yes Yes

OCS-0829 Ship

Shoal Block 219:

Well No. 1. 6/2/64 6/22/64 No No

Well No. 2. 7/14/64 9/20/64 Yes Yes

Well No. 3. 7/8/65 8/10/65 Yes Yes

Well No. 4. 9/3/65 10/20/65 Yes Yes

Well No. 5. 8/31/68 9/24/68 Yes Yes

At the time of acquisition, West Delta Block 89 was thought to be a low relief anticlinal high structure and was determined to be such by subsequent drilling. The structure was found to be broken by faulting. Because of such faulting, well No. 5 was drilled as a "wildcat” well. Had well No. 5 found what was indicated by the G & G information, it would have been considered to be the platform site. However, well No. 3 was selected as the site for platform C. On June 27, 1968, it was decided to drill a platform replacement well to develop the hydrocarbon-bearing sands found by well No. 5. Physical abandonment of well No. 5 was completed on July 7, 1970. A 10-well platform was set over well No. 3, but only 4 platform wells were drilled because the drilling from the platform disclosed that the originally estimated size of the reservoir was excessive due to faulting.

Eugene Island Block 205 is a piercement salt dome structure. Well No. 4, block 205, was drilled as a "wildcat” well, was left in a condition for reentry, and was classified by Texaco as a "shut-in oil (single)” well. It was abandoned in 1971 after plans had been made for a possible replacement platform well to be drilled into block 205 from the "A” platform in block 206. Well No. 5, block 205, was drilled as an "extension” well and was left in a condition for reentry. It was classified by Texaco as a "not tested — shut in” well and was abandoned in 1971. Plans had been made for a possible replacement well to be drilled from the "A” platform. A platform replacement well to be drilled from the "A” platform in block 206 was authorized in May 1970 to develop the oil sand found by well No. 5. Platform well No. A-3 was spudded on November 27, 1970, and completed on January 24, 1971. Four platforms have been used for drilling wells into block 205. Only platform "D” was located in block 205. All of the platforms were set over wells previously drilled by mobile rigs which were then reentered and completed for production.

Ship Shoal Block 219 is a piercement salt dome structure. Well No. 5, block 219, was drilled as an "extension” well with dual oil completion anticipated. In March 1969 Amoco Production advised the U.S. Geological Survey of the Department of Interior that plans were being made to commence the construction of a platform in late April 1969 in block 219. Abandonment of well No. 5 was authorized in 1971 because it no longer had any utility due to the drilling of a replacement well from the "A” platform. Replacement platform well No. A-4 was spudded on September 5, 1970, and completed on May 29, 1971.

Prior to August 28, 1969, the U.S. Geological Survey of the Department of Interior could not approve the productibility of oil and gas wells in the Gulf unless underwater casing stubs were left extending above the mudline of the Gulf floor. As of August 28, 1969, USGS order No. 4 was revised to permit approval of the productibility of wells even though the casing was cut off below the mudline. Because of the difficulties casing stubs caused for the fishing industry, wells in the Gulf of Mexico are physically abandoned when they have no further utility.

Pursuant to a letter dated October 7, 1970, the USGS advised Amoco Production of "recent rules and regulations” which included the following:

Justification for existing or planned under-water casing stubs should explain what work is to be done (platform installation, re-entry, etc.), and a definite time schedule for the work to be performed.

Prior to the date of the letter OCS-1088 block 89 well No. 5, OCS-0805 block 205 well No. 5, and OCS-0829 block 219 well No. 5 had been replaced by platform wells. Replacement by a platform well was planned for OCS-0805 block 205 well No. 4.

In his statutory notice of deficiency, the Commissioner determined that the four wells drilled by mobile rigs in West Delta Block 89, Eugene Island Block 205, and Ship Shoal Block 219 during 1967 and 1968 were drilled primarily to obtain geological information, not for the production of oil and gas, and, therefore, disallowed the deductions claimed for intangible drilling costs incurred in connection with the wells. He further determined that the expenses were incurred for exploratory operations and were thus capital costs of the properties concerned.

Amoco U.K.

During the taxable years 1967 through 1969, Amoco (U.K.) Exploration Co. (Amoco U.K.), a Delaware corporation, was engaged in the business of acquiring, exploring, and developing oil and gas properties in the offshore waters of the United Kingdom, principally in the North Sea, and producing and selling its share of the oil and gas from such properties.

Prior to 1967 Amoco U.K. and three unrelated parties, the British Gas Council, Amerada Petroleum Corp., and North Sea Inc. (referred to collectively as the Gas Council-Amoco Group or the Amoco Group) acquired oil and gas working-interest rights in several large areas covering over 500,000 acres in the United Kingdom sector of the North Sea, including blocks 49/18, 49/23, 49/27, and 22/18. The working-interest rights were created by two separate licenses, each dated September 17,1964, granted by the Minister of Power of the United Kingdom.

Prior to 1967, Amoco U.K. and its coowners had drilled three wells (Nos. 49/18-1, 49/23-1, and 49/27-1) in blocks 49/18, 49/23, and 49/27 from mobile rigs. During the years 1967 through 1969 nine more wells were drilled from mobile rigs in such blocks and in block 22/18. The numbers of the wells and the fields in which they were located are as follows:

Well number Field

49/18-1.Indefatigable

49/18-2.Indefatigable

49/18-3.Indefatigable

49/18-4.Indefatigable

49/23-1.Indefatigable

49/23-2.Indefatigable

49/23-3.Indefatigable

49/27-1.Leman

49/27-2.Leman

49/27-3.Leman

49/27-4.Leman

22/18-1.Montrose

Amoco U.K. incurred the following intangible costs during the years 1967 through 1969 in connection with the drilling of these wells:

The following is a schedule showing, with respect to each of the wells listed above, the spud date, the drilling completion date, whether any potentially producible hydrocarbon-bearing zone was found, and whether the well was left in condition for reentry to the potentially producible hydrocarbon-bearing zone:

Property name and well number Spud date Date drilling operations completed Potentially producible hydrocarbon-bearing zone? Left in condition for reentry?

Indefatigable:

49/18-1. 4/8/66 6/12/66 Yes Yes

49/18-2. 2/3/67 4/17/67 Yes Yes

49/18-3. 6/10/67 8/28/67 Yes Yes

49/18-4. 10/23/67 12/13/67 Yes Yes

49/23-1. 9/22/66 12/11/66 Yes Yes

49/23-2. 4/1/67 6/9/67 Yes Yes

49/23-3. 9/2/67 11/1/67 Yes Yes

Leman:

49/27-1. 6/13/66 9/21/66 Yes Yes

49/27-2. 12/12/66 2/3/67 Yes Yes

49/27-3. 1/27/67 3/30/67 Yes Yes

49/27-4. 4/18/67 6/6/67 Yes Yes

Montrose:

22/18-1. 5/1/69 12/28/69 Yes Yes

Wells 49/18-2, 3, and 4, wells 49/23-2 and 3, and wells 49/27-2, 3, and 4 were each drilled as possible platform locations and were left in a condition for reentry to the hydrocarbon-bearing zones. Well 22/18-1 was drilled to a deep postulated horizon which proved to be dry; however, oil was found in a more shallow structure. A subsea completion is presently being considered to produce the oil found by well 22/18-1.

The Leman Field was discovered in April 1966 by the Shell-Esso well 49/26-1. The Indefatigable Gas Field was discovered by Amoco Council Group’s well 49/18-1, drilling operations in connection with which were completed on June 12, 1966.

When natural gas was first discovered in offshore United Kingdom in 1966, there was no immediate market for it in England. At that time the United Kingdom had a system of using gas manufactured in each town and there was no interconnecting pipeline route of any kind. The type of gas being used was not the same as natural gas. Before the natural gas could be used, a pipeline system had to be developed both from the wells to the shore and then from the shore to the towns; and then in the towns it was necessary to change the existing local pipeline grid and to alter every valve and every gas appliance that was going to be using natural gas.

When the Amoco Gas Council Group first found gas in well 49/18-1, the formation appeared to be very tight; they were not sure how easily the gas would flow from distant points to the well and what the ultimate spacing of the wells would be. It was thought that a number of scattered platforms might have to be used and that four-well platforms might have to be scattered all over the field and placed over the wells drilled by mobile rigs. In a report dated July 29, 1966, relating to blocks 49/18 and 49/27, appears the following statement:

The delineation wells will be drilled with mudline casing suspension systems so they can be suspended and either abandoned or completed from a platform at a later date. While the program does not provide for completing any of the delineation wells, it may prove desirable to set four-well platforms over these wells and complete them rather than drilling new wells in the event sufficient pay is encountered for a commercial completion. The cost of drilling a new straight well from one of the platforms, however, may not be much more than the cost of re-entering and completing one of the suspended delineation wells.

In a report dated August 3, 1966, it was concluded that "the costs for a replacement well will be about $500,000 higher than the cost to reenter a suspended well.”

After drilling the first discovery wells, the Amoco Gas Council Group realized that a commercial field worth developing was probable; therefore, on their first well and later delineation wells they used a sea-bottom casing suspension system so that the wells could be used at a later date for production from a formation.

Platform 49/18-A was installed in July 1968 over well 49/18-4, which was reentered and redesignated as well 49/18-A1 and completed for production. Platform 49/18-B was installed in August 1973 under the following circumstances. Unsuccessful attempts had been made in 1968 to locate well 49/18-1 in order to set platform A over that well. Well 49/18-1 then could have been reentered and tied back to the platform and produced. Platform A was then set over well 49/18-4. Well 49/18-1 was later located and it was then decided to locate Indefatigable Field platform B over the well. However, a sea-bottom survey showed that due to scouring around the well casing the water depth had increased in the vicinity of the well from the originally surveyed depth of 98 feet to 103 feet. The design and modification of a platform for 103 feet of water seemed impractical. In August 1973, platform B was installed 400 feet south of well 49/18-1. To date, no platform has been installed in block 49/23.

Platform 49/27-A was installed over well 49/27-1 in July 1967 and platform 49/27-C was installed over well 49/27-2 in July 1968. Both wells were reentered and completed for production.

Amoco U.K. has installed a platform in the Montrose Field 2 or 3 miles north of well 22/18-1. Because it is doubted that the area surrounding well 22/18-1 warrants another platform, the possibility of making a subsea completion of well 22/18-1 and hooking it up to the platform to the north is under consideration by the operators.

No four-well platform has been used to develop either the Indefatigable Field or the Leman Field. This was because (1) it was found that the permeability was better than had been anticipated and (2) it was also found to be more economical to use 12-well platforms and consequently fewer platforms. In the future in outlying areas of these fields, two-well or four-well platforms or subsea completions may be used.

In his statutory notice of deficiency, the Commissioner determined that wells 49/18-2, 49/18-3, 49/23-2, 49/27-2, 49/27-3, 49/27-4, and 22/18-1 were not drilled for the production of oil and gas and, therefore, disallowed the intangible drilling costs incurred in connection with drilling the wells. He further determined that expenses were incurred in connection with further exploratory operations and thus were capital costs of the properties concerned.

Amoco Trinidad

During the taxable years 1967 through 1969, Amoco Trinidad, a Delaware corporation, was engaged in the business of acquiring, exploring, and developing oil and gas properties in offshore Trinidad waters and producing and selling its share of the oil and gas from such properties.

On January 10, 1961, Amoco Trinidad (then known as Pan American Trinidad Oil Co.) and two partners, Trinidad Sun Oil Co. and Pure Oil Co. of Trinidad, Inc., acquired from the Government of Trinidad an exclusive license giving them all the oil and gas working-interest rights in approximately 2 million gross acres in the offshore waters of Trinidad. On April 12, 1961, 105,344 acres were surrendered to Dominion Oil Ltd. On October 10,1961, an additional 950,000 acres were surrendered to the Government of Trinidad, leaving approximately 944,000 acres under the license. Pursuant to assignments on March 31, 1962, September 25, 1964, and October 15,1965, Amoco Trinidad acquired the entire working interest in the remaining acreage under the license. The acreage included the Offshore Point Radix (OPR) area (which included the Teak and Samaan Fields) and the Southeast Galeota (SEG) area. The two areas were located 22 to 35 miles from the Trinidad mainland.

Prior to 1967, Amoco Trinidad had drilled one well (OPR 1) from a mobile rig in the OPR area. During the years 1967 through 1969 Amoco Trinidad drilled four more wells in the OPR area and four wells in the SEG area. The numbers of such wells and the area in which each was located are as follows:

Well number Area

SEG 1.Southeast Galeota (SEG)

SEG 2.Southeast Galeota (SEG)

SEG 3.Southeast Galeota (SEG)

SEG 4.Southeast Galeota (SEG)

OPR 1.Offshore Point Radix (OPR)

OPR 2.Offshore Point Radix (OPR)

OPR 3.Offshore Point Radix (OPR)

OPR 4.Offshore Point Radix (OPR)

OPR 5.Offshore Point Radix (OPR)

Amoco Trinidad incurred intangible costs in connection with wells drilled during the years 1967 through 1969 as follows:

Well number 1967 1968 1969

SEG 1. $2,131,796.55 $1,204,919.61 $9,797.65

SEG 2. 1,707,625.09 20,826.48

SEG 3. 942,424.62 275,674.58

SEG 4. 1,115,243.79

OPR 2. 1,490,452.00 87,610.43

OPR 3. 2,659,790.95

OPR 4. 2,027,264.04

OPR 5. 2.510.666.18

Totals. 2,131,796.55 5,345,421.32 8,706,874.10

The following is a schedule showing, with respect to each of the wells listed above, the spud date, the date drilling operations were completed, whether any potentially producible hydrocarbon-bearing zone was found, and whether the well was left in condition for reentry to any potentially producible hydrocarbon-bearing zone:

During the years 1967,1968, and 1969, Amoco Trinidad was trying to locate oil in producible quantities off the eastern coast of Trinidad. Its first discovery in each of the SEG and OPR areas was gas. Gas was found, in OPR 2. The first major discovery of oil was in OPR 4. Faulting caused the structural relationship between wells to differ greatly. At the time of the discovery of gas in the Trinidad areas, there was no commercial market for the gas. The company hoped to develop a market for the gas. The wells which located gas in producible quantities were left in condition so they could be reentered.

None of the wells drilled during the years 1967 through 1969 was drilled for information only. Each was drilled in the hope that oil in producible quantities would be found. The price of oil then was about $2 a barrel. Any number of ways in which potentially producible wells might be completed, including sea floor completions or using platforms of varying sizes, were considered. If sufficient oil had been found, each well could have been a location for a platform.

The first platform (Teak A platform) installed in offshore Trinidad in 1970 was located near OPR 4, Amoco Trinidad’s first major oil discovery in the area. An attempt was made to locate the platform over OPR 4 but was not successful because of severe current and wave conditions. Teak B platform was installed near OPR 5 in 1971. With the exception of OPR 3 which was replaced by wells directionally drilled from the Teak B and Teak D platforms, none of the wells drilled during the years 1967 through 1969 had been reentered from a permanent platform or replaced by a directionally drilled well as of December 31, 1975.

On March 19, 1976, Amoco Trinidad entered into a contract providing for the purchase of gas by the National Gas Co. of Trinidad & Tobago, Ltd., over a period ending on December 31, 1999. Amoco Production dedicated to the performance of this contract "all associated gas reserves and all economically recoverable reserves” in specified offshore Trinidad waters, including the Teak, Samaan, and SEG Fields.

In his statutory notice of deficiency, the Commissioner determined that the intangible drilling costs pertaining to SEG 1, 2, 3, and 4 and OPR 2, 3, 4, and 5 were not incurred for the drilling and preparation of wells for the production of oil and gas and, therefore, disallowed the deductions claimed for such costs. He further determined that the expenses were incurred in connection with exploratory operations having the purpose of obtaining geological information and thus were capital costs of the property involved.

OPINION

On petitioner’s consolidated Federal income tax returns for the taxable years 1967, 1968, and 1969, deductions were claimed for intangible drilling and development costs incurred by Amoco Production Co., Amoco U.K., and Amoco Trinidad in connection with the drilling of certain wells from mobile drilling rigs in the Gulf of Mexico, the North Sea, and offshore Trinidad waters. These deductions were disallowed by respondent in his statutory notice of deficiency on the ground that the expenditures represented costs of exploratory operations and should be treated as capital costs of the properties concerned. It was further determined that the expenditures were not incurred in connection with the drilling of wells for the production of oil and gas.

Respondent’s position with respect to each of the 20 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), I.R.C. 1954. In particular, respondent’s position is that petitioner has not satisfied the requirements of section 1.612-4, Income Tax Regs., because it has not been shown that: (1) The expenditures in question constitute "intangible drilling and development costs incurred * * * in the development of oil and gas properties,” or (2) the expenditures were "incident to and necessary for the drilling of wells and the preparation of wells for the production of oil or gas.” He contends that the wells in issue represent, in reality, an extension of exploratory work of the type not coming within the ambit of the option to deduct intangible drilling and development costs; that the physical means by which the operations were conducted should not be controlling; and that the wells were not drilled with an intention to attempt completion of each well as in the case of a "normal” oil and gas well. More concisely, he maintains that until an operator has made the decision to install a permanent drilling platform to produce hydrocarbons available at a site, the operator’s intangible costs are not for "development” within the meaning 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 petitioner’s consolidated 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. Petitioner concedes that all of the expenses in question are capital expenditures described in section 263(a). 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 history of and the congressional purpose underlying the optional treatment of intangible drilling and development costs, "Congress favors a liberal interpretation of the regulation.” Exxon Corp. v. United States, 547 F.2d 548, 555 (Ct. Cl. 1976). This conclusion by the Court of Claims, sitting en banc, is further supported by the recent amendment to section 57(a)(ll) limiting the tax-preference treatment of intangible drilling and development costs. See 123 Cong. Rec. S6699-6702 (daily ed. Apr. 28, 1977).

Respondent’s basic contention is that the drilling of the wells in question represents an extension of exploratory operations similar to geological and geophysical surveys, the costs with respect to which must be capitalized under Louisiana Land & Exploration Co. v. Commissioner, 7 T.C. 507 (1946), affd. 161 F.2d 842 (5th Cir. 1947), and I.T. 4006, 1950-1 C.B. 48. He maintains that the mere drilling of wells, as petitioner contends, is not sufficient to come within the option, for the reason that "development” of the property within the meaning of the regulations is not undertaken until a decision has been made to install a permanent drilling and production platform.

The classification of the activities in issue as "exploratory” lends no support to respondent’s position. The use of the term, he erroneously assumes, carries with it the requirement of capitalization. Both the terms "exploratory” and "development” have been used in a broad sense in the field of oil and gas taxation. Both terms have been used to describe activities which must be capitalized, such as seismic surveys, as well as operations which clearly fall within the IDC option. In Louisiana Land & Exploration Co. v. Commissioner, supra, the petitioner sought to deduct the cost of conducting a geophysical survey on property held under a lease at the time the survey was made. This Court held that the cost involved constituted a capital expenditure, rather than an ordinary and necessary business expense. In so holding, we stated at pages 515-516:

It thus appears that the results of this survey were to guide petitioner in determining generally whether and to what extent these large areas of land should be explored by drilling wells. Whether or not the scientific knowledge gained from the survey indicated that drilling would be successful or unsuccessful, it was undoubtedly the information upon which would be based further tests and potential drilling operations during the entire period of petitioner’s exploitation of the land for oil and gas. * * * This survey was not connected with the drilling of any particular well or wells and was not confined to any restricted area which had been tentatively singled out as the location of a well. Under these circumstances it seems abundantly clear that the survey was the first step in the over-all development for oil of these tracts of land and that the benefit derived from the expenditure was to be enjoyed by petitioner in its business during the entire useful life of the asset being developed. * * * [Emphasis added.]

In F.H.E. Oil Co. v. Commissioner, 147 F.2d 1002 (5th Cir. 1945), the Fifth Circuit concluded that all intangible drilling costs were capital in nature and that the predecessors to the regulations in question were contrary to law. Although the court thereafter limited its holding to a narrower scope, F.H.E. Oil Co. v. Commissioner, 149 F.2d 238 (5th Cir. 1945), Congress adopted Concurrent Resolution 50 declaring that the regulations allowing the deduction of intangible drilling costs had been recognized and approved by Congress. In House Report 761 accompanying the resolution appears the following language:

The uncertainty occasioned by raising doubts as to the validity of these regulations is materially interfering with the exploration for and the production of oil. * * * [H. Rept. 761, 79th Cong., 1st Sess. 2 (1945). Emphasis added.]

More recently, in Exxon Corp. v. United States, 547 F.2d 548 (Ct. Cl. 1976), the court stated at page 555:

Congress has consistently viewed the optional treatment of IDC as an incentive to oil and gas prospecting and exploration, clearly a continuing objective of national importance. * * * [Emphasis added.]

In addition, the following discussion accompanied the introduction of a Senate floor amendment to the Tax Reduction and Simplification Act of 1977 limiting the amount of intangible drilling costs constituting an item of tax preference:

In the period 1969 through 1973, independent producers in the United States drilled 9 out of 10 exploratory — wildcat—wells, found 54 percent of the oil and gas discovered, and accounted for 75 percent of the "significant” petroleum discoveries as defined by the American Association of Petroleum Geologists.
Drilling is an extremely high risk business. Only one exploratory well in nine produces anything. Eight out of nine exploratory wells are dry holes. In addition, at least 20 percent of developmental wells are dry holes. * * * In order to prevent increasing dependence on overseas oil, our tax laws must not discourage risk taking in the oil and gas business.
The 15-percent penalty tax on intangible drilling costs discourages active wildcatting which is so important to our energy needs.
Any delay in enacting this amendment will result in reductions in desperately needed exploratory drilling.
[123 Cong. Rec. S6701-6702 (daily ed. Apr. 28, 1977). Emphasis added.]

It is clear from the above examples that the classification of an activity as "exploratory” does not necessarily remove it from the scope of the IDC option. Indeed, it would seem from the last three examples that it is the drilling of the exploratory-type well, as opposed to development wells, which Congress has the greater interest in encouraging by means of the IDC option. Realizing this, we must now turn to our task of deciding whether the exploratory wells in question come within the scope of the option which requires us to determine at what point "development” within the meaning of the regulations begins.

Respondent maintains that "development” within the meaning of the regulations does not begin until an operator of offshore oil and gas properties makes the decision to commence production drilling; that is, the time the decision is made to install a permanent drilling and production platform. Until that point is reached, he argues, all costs of exploratory wells must be capitalized.

Respondent’s position finds no support in the language of the regulations or the relevant authorities and is indeed contrary to both. As previously mentioned, the classification of an activity as exploratory does not necessarily carry with it the requirement of capitalization. The regulations specifically provide that the "option applies to all expenditures * * * incident to and necessary for the drilling of wells.” The first example includes within the option "all amounts paid * * * in the drilling * * * of wells,” the very activity with which we are concerned. The second example provides for the inclusion within the option of those activities "as are necessary in the preparation for the drilling of wells.” In Louisiana Land & Exploration Co. v. Commissioner, we stated (7 T.C. at 516):

The option is directed to the costs of preparations for the drilling of particular wells after the drilling has been at least tentatively decided upon, which preparations are far removed from over-all geophysical exploration such as we are here considering.

It is clear from the language of the regulations, including the first two examples, and the above language of this Court in Louisiana Land & Exploration Co. that -the dividing line between "exploratory” work which must be capitalized and "development” activities coming within the IDC option is the point at which the preparations for drilling begin. There is nothing in the regulations which either expressly or implicitly limits the "wells” to those drilled after a decision has been made to install a permanent drilling and production platform. To so hold would be inconsistent with the long-standing construction and natural meaning of the regulations. Moreover, "By the expedient of a stingy reading, one should not frustrate the obvious Congressional purpose to encourage oil and gas prospecting, for to do so would be the most emphatic type of judicial legislation.” Exxon Corp. v. United States, 547 F.2d 548, 558 (Ct. Cl. 1976). Therefore, the restrictive reading given the regulations by respondent must be disapproved and we conclude that the intangible costs of drilling all offshore wells, including those wells drilled with mobile rigs, are subject to the IDC option.

A consideration of the ramifications of respondent’s position that the optional treatment accorded by section 1.612-4, Income Tax Regs., is limited to those expenses incurred after a decision has been made to set a platform illustrates the fallacy of his argument. Under respondent’s interpretation of the regulations the costs of virtually all wells drilled in unproven waters would be capitalized. The dominant purpose of an offshore wildcat well, like that of a similar well drilled onshore, is to determine whether hydrocarbons are actually present in a structure. Yet respondent’s theory has the effect of removing from the ambit of the IDC option the costs of drilling these exploratory wells and limiting it primarily to the intangible costs of "development” wells drilled from a platform after the areal extent of the reservoir has been approximately delineated. Respondent’s theory is erroneous with respect to wildcat wells for two reasons: (1) The dominant purpose of both onshore and offshore wildcat wells is identical, and (2) it is the drilling of this type of well, as opposed to "development” wells, which Congress has the greater interest in encouraging by means of the IDC option. See 123 Cong. Rec. S6699-6701 (daily ed. Apr. 28, 1977).

Respondent’s theory would also result in the disallowance of IDC even in the case of those wells drilled with mobile rigs which have been reentered from a platform or produced by means of a subsea completion system. It is apparent that requiring capitalization of the drilling costs of a producing well is contrary to the provisions of section 263(c) and section 1.612-4, Income Tax Regs., and, therefore, any theory which would require capitalization in such instances must be erroneous. The stipulated facts reflect that of the eight drilling platforms which have been installed in the blocks involved or in adjacent blocks in the Gulf of Mexico, six were set over and used to complete for production wells drilled with mobile rigs. Since 1962, of the 42 wells drilled with mobile rigs by Amoco Production, 14 have had permanent drilling and production platforms set over them and have been reentered from such platforms. Under respondent’s theory, the portion of the costs of the drilling of these wells with mobile rigs would be capitalized despite the fact that they were clearly costs of drilling producing wells.

It has been recognized in those cases dealing with IDC option that its purpose is to encourage the risking of capital. In United States v. Cocke, 399 F.2d 433 (5th Cir. 1968), the Fifth Circuit held that the carrying party in a carried-interest arrangement was entitled to depletion and the "subservient satellites” of depletion, including intangible drilling and development costs, during the period of recoupment. In so holding, the court stated at page 452:

The argumentative justification for liberality in taxation of oil and gas is that such liberality encourages and emboldens the fiscally timid to exploit the hidden resource. It rewards the risk-taker. * * *

This Court applied the same theory in Haass v. Commissioner, 55 T.C. 43, 50 (1970), where the petitioner had acquired his interests in the wells after the drilling had been completed. Although the results of the drilling were unknown to him at the time of acquisition, that information could have been ascertained by him prior to his agreement to pay for those costs previously incurred. The risk element having been removed, we denied the deduction for IDC, stating:

The regulations do not contemplate that investors * * * [can be] allowed a deduction for intangible drilling costs without assuming the risks of the unknown result of the drilling. * * *

Thus, it is clear that risk and IDC are inextricably related. The effect of respondent’s position is that it places the high-risk costs of exploratory wells in the same category for income tax purposes as the low-risk costs of seismic surveys and limits the deduction primarily to the costs of platform wells where the likelihood of encountering hydrocarbons is greater and the risk is arguably less. Such an interpretation of the regulations would frustrate the congressional purpose of encouraging the risking of capital for oil and gas exploration.

Finally, it may be several years after the drilling of a well with a mobile rig that exploration of an oil and gas property is completed and production commences. Under respondent’s theory any deduction of the large costs of drilling most wells with mobile rigs would be postponed until that time. This result is in contrast to the usual situation where amortization, depreciation, or depletion of a capital expenditure begins soon after the completion of the particular project or undertaking with respect to which the costs are incurred. Similarly, any deduction for the cost of dry holes might be postponed until the property is disposed of or abandoned, clearly contrary to prevailing practice. See secs. 1.612 — 4(b)(4) and 1.614-6(d), Income Tax Regs.; Rev. Rul. 69-332, 1969-1 C.B. 87; Rev. Rul. 58-231, 1958-1 C.B. 247. Both of these consequences of capitalization would have the effect of increasing the costs of oil and gas exploration. It was no doubt this very effect of the Fifth Circuit’s holding in F.H.E. Oil Co. v. Commissioner, 147 F.2d 1002 (5th Cir. 1945), requiring the capitalization of intangible drilling costs long considered deductible which prompted the adoption of House Concurrent Resolution 50 and the following statement in House Report 761:

The uncertainty occasioned by raising doubts as to the validity of these regulations is materially interfering with the exploration for and the production of oil. * * * [H.Rept. 761, 79th Cong., 1st Sess. 2 (1945).]

The similarity to the situation herein is too obvious to require elaboration.

The primary basis for respondent’s contention that the drilling of the wells in question merely represents an extension of exploratory operations similar to seismic surveys is that they were not drilled with the same intention to attempt completion as in the case of an onshore oil or gas well. The answer to respondent’s contention is simply that the regulations contain iio requirement of an intention to complete and produce a particular well. The first example in the regulations specifically provides that the IDC option applies to "all amounts paid * * * in the drilling * * * of wells,” without any qualifying language. Nor does there appear to be any case or published ruling supporting such a requirement in the 60-year history of the regulations. Indeed, the little authority that exists is to the contrary. For instance, it is clear that it is never intended that hydrocarbons will be produced from water injection wells. Yet in Rev. Rul. 69-583, 1969-2 C.B. 41, the Commissioner held that intangible drilling costs of water injection wells necessary in the primary development of oil property are subject to the IDC option.

In any event we are satisfied that each of the wells in question would qualify for IDC treatment under any reasonable "intent to produce” test which might be formulated for application to wells drilled from mobile rigs in offshore waters. After carefully reviewing the testimony of petitioner’s witnesses regarding the location of the wells and their explanations respecting particular statements in certain documents, we are satisfied that none of the wells was drilled solely for the purpose of gaining information and that each was drilled at a location considered to be a potential platform site. Production casing was authorized to the total depth of each well and was installed in each well which located potentially producible hydrocarbons. One reason for the installation of the production casing was to make it possible to utilize the well in the future for either a subsea completion or a tieback to a platform. Each of these wells was left in a condition for reentry to hydrocarbon-bearing zones with a subsea suspension of all casing strings. Thus, it seems that petitioner’s subsidiaries had much the same intent at the time each well was spudded as an operator of an onshore well; that is, the well would be produced if it were economically feasible to do so. While it is true that fewer offshore wells which locate hydrocarbons are completed for production than in the case of onshore wells and that information-gathering has a more significant purpose, these differences are due solely to the higher costs of production offshore and should not, standing alone, result in the disallowance of IDC treatment under any "intent to produce” test. Even onshore wells which locate hydrocarbons may not be produced for economic reasons. For example, gas wells may be capped because the quantity of gas may not justify the cost of a pipeline. However, the costs of such wells clearly come within the option. See Louisiana Land & Exploration Co. v. Commissioner, 7 T.C. 507, 511 (1946), affd. 161 F.2d 842 (5th Cir. 1947).

The complexities involved in applying any such "intent to produce” test to offshore wells drilled with mobile rigs provide another reason for adopting an interpretation of the regulations under which the intangible costs of all wells drilled to a postulated oil or gas deposit qualify for the IDC option. In Exxon Corp. v. United States, 547 F.2d 548, 560-561 (Ct. Cl. 1976), Judge Bennett reasoned as follows:

A strong reason, not elsewhere articulated, for interpreting the regulation as the trial judge and plaintiff would have us read it is that their interpretation is workable. Defendant’s reading of the regulation, on the other hand, would present substantial difficulties in the administration of the tax laws. The court should not strain to reach an interpretation, not clearly compelled, that would have such a result. Commissioner v. Brown, 380 U.S. 563, 571, 85 S.Ct. 1162, 14 L.Ed.2d 75 (1965); Steuer v. United States, 207 Ct.Cl. 282, 294 (1975); Kantor v. United States, 205 Ct.Cl. 1, 6 (1974). * * *
Were we to follow defendant’s reading of the regulation, the accounting for each platform would potentially revolve about fact problems not at all readily resolved or resolvable. Considering the number of platforms built (with changing technology) by a variety of drilling operators since 1954, and yet to be built, the problem takes on staggering proportions. For the added reason that defendant’s interpretation of the regulation would be altogether cumbersome in application for the taxpayer, the IRS, and for the courts when the first two cannot agree, the court does well to avoid that interpretation and to stand by the reading that it adopts.

The difficulties posed by the use of any subjective test to determine whether the intangible costs of any well should qualify for the IDC option are no better illustrated than by the extensive, detailed testimony and hundreds of exhibits required in the instant case. Any subjective test would have to take into account the state of technology, ocean conditions, economic considerations, correspondence between parties having some interest in the drilling of the well, whether that interest be financial or regulatory, and the geological information available at the time of the drilling of each well. When it is recognized that there are a far greater number of wells drilled from mobile rigs than there are drilling platforms such as in the Exxon case, the administrative problems involved in applying such a test become more apparent. Therefore, we should not strain to reach an interpretation of the regulations requiring the use of a test resulting in such substantial problems of administration and application unless it is clearly required by the language of the regulations. It is obvious that no such test is compelled by the regulations.

Prior to concluding, the quotation of Judge Davis’ observation in his concurring opinion in Exxon Corp. v. United States, supra at 559, seems particularly appropriate. On page 560, he concluded as follows:

Perhaps the regulation, which was formulated before off-shore drilling was foreseen, is too all-embracing for current conditions. Perhaps it should be narrowed as [respondent] wishes. If so, the proper method is by prospective amendment[] of the regulation or by legislation, not by an attempt to read [the] regulation in a drastic new way, inconsistent with its long-standing terms and format, as well as contrary to its natural meaning. [Fn. ref. omitted.]

Accordingly, we hold that the intangible costs incurred in drilling the 20 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 petitioner’s consolidated income tax returns.

Decision will be entered under Rule 155. 
      
       All section references are to the Internal Revenue Code of 1954, as amended.
     
      
       For Federal income tax purposes, a working interest is an interest in minerals in place which is burdened with the cost of development and operation of the property. Breeding, Burke, & Burton, Income Taxation of Natural Resources, sec. 2.04 (1977).
     
      
       An anticline is a subsurface, geological structure in the form of a sine curve; that is, the formation rises to a rounded peak. Anticlinal structures in sedimentary rocks are good prospects for drilling because any oil in the deposit will normally rise to the highest point in the structure. Williams & Meyers, Manual of Oil and Gas Terms 19 (3d ed. 1971).
     
      
       A piercement salt dome is a mound or plug of salt which intrudes into the formations above it, causing faulting. Substantial amounts of oil are found around salt domes, especially in Louisiana where they are prevalent. Oil may be produced from the caprock usually found on top of a piercement-type dome, from fault traps along the sides of the dome, and from various horizons in the anticline lying over the dome. Williams & Meyers, supra at 401.
     
      
       The intangible costs of well No. 49/18-4 are omitted. The deduction claimed for intangible drilling and development costs incurred with respect to such well was not disallowed in the statutory notice of deficiency.
     
      
       The parties have stipulated that the determination includes the intangible costs and recoveries for well No. 49/23-3 even though the well was not specifically identified in the statutory notice of deficiency.
     
      
       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 betterments 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, 547 F.2d 548, 553-554 (Ct.Cl. 1976); Fielder, "The Option to Deduct Intangible Drilling and Development Costs,” 33 Texas L. Rev. 825 (1955); Mahin, "Deduction for Intangibles,” 2d Oil & Gas Inst. 367 (1951).
     
      
       A wildcat well is an exploratory well drilled in unproven territory; that is, in a horizon from which there is no production in the general area. Williams & Meyers, Manual of Oil and Gas Terms 509 (1975).
     
      
       Linden, "Review of Offshore Drilling — What are Intangibles?” 26th Oil & Gas Inst. 441, 462 (1976).
     
      
       See Linden, "Review of Offshore Drilling — What are Intangibles?” 26th Oil & Gas Inst. 441, 451-461(1975).
     
      
       For the definition of the term "property” as used in the field of natural resources taxation, see sec. 614, I.R.C. 1954.
     
      
       See Breeding, Burke & Burton, Income Taxation of Natural Resources, sec. 14.16 (1977); Haschke & Currin, "Recent Cases and Rulings,” 24 Oil & Gas Quarterly 511, 514 (June 1976).
     
      
       It is subject to question whether respondent could amend the regulations to conform with his position herein and at the same time comply with the requirement of sec. 263(c) that the regulations correspond to the regulations granting the IDC option which were recognized and approved in House Concurrent Resolution 50. Compare sec. 29.23(m)-16, Regs. Ill (1943), with sec. 39.23(m)-16, Regs. 118 (1951), and sec. 1.612-4, Income Tax Regs. (1965).
     