
    Louisiana Land and Exploration Company and Subsidiaries, Petitioner v. Commissioner of Internal Revenue, Respondent
    Docket No. 10246-89.
    Filed January 19, 1994.
    
      
      William M. Linden, David B. Gerger, Thomas Crichton TV, Margaret A. Wilson, and Henry Binder, for petitioner.
    
    
      Thomas R. Ascher, Patrick Putzi, and Marsha A. Keyes, for respondent.
    
      
       Brief amicus curiae was filed by Stephan G. Dollinger as attorney for the American Petroleum Institute.
    
   Clapp, Judge:

Respondent determined deficiencies in petitioner’s Federal corporate income taxes as follows:

Year Deficiency

1984 . $36,646,062

1985 . 3,615,049

After concessions, the issues for decision are: (1) Whether the nonmaterial costs of fabricating certain modules that are structural components of an offshore drilling and production platform are properly deductible as intangible drilling and development costs (idc) under section 263(c); (2) whether the nonmaterial costs of installing certain equipment housed in such modules are properly deductible as idc under section 263(c); (3) whether, for purposes of calculating the percentage depletion deduction for sulphur under section 613, the extraction of sulphur from hydrogen sulfide gas utilizing the Claus method qualifies as mining; and (4) whether, for purposes of applying the 50-percent of taxable income limitation on the percentage depletion deduction under section 613(a), taxable income from the property includes only income from the sale of sulphur.

Unless otherwise indicated, all section references are to the Internal Revenue Code as in effect for the years in issue, and all Rule references are to the Tax Court Rules of Practice and Procedure.

FINDINGS OF FACT

Some of the facts have been stipulated and are so found. We incorporate by reference the stipulation of facts, the first through sixth supplemental stipulations of facts, and attached exhibits.

Petitioner is an affiliated group of corporations whose common parent is Louisiana Land & Exploration Co., a Maryland corporation that maintains its principal office in New Orleans, Louisiana.

For the years in issue, petitioner filed consolidated corporate income tax returns. It maintained its books and filed its income tax returns on a calendar year basis utilizing the accrual method of accounting.

Petitioner is primarily engaged in the exploration for and the development, production, refining, and sale of crude oil and natural gas and the exploration for and production and mining of other minerals, such as sulphur, in the United States and several foreign countries.

Brae A and Brae B Platforms and the Disputed Modules Generally

On January 25, 1980, petitioner entered into a joint operating agreement with 11 other participants to exploit certain oil and gas deposits in the North Brae development area of the North Sea. Marathon Oil U.K., Ltd., was the project’s operator. The North Brae development area is located within the territorial waters of the United Kingdom, approximately 150 miles off the coast of Scotland. The exploitation of the oil and gas deposits required the construction, transportation, and installation of two offshore drilling and production platforms, the Brae A and Brae B platforms. The Brae B platform is located approximately 10 miles north of the Brae A platform.

Under the joint operating agreement, petitioner received a working interest in the oil and gas deposits. During 1984 and 1985, petitioner incurred a pro rata share of the Brae B platform’s construction costs and the construction costs of module 65 on the Brae A platform, including certain nonmaterial costs.

The Brae A and Brae B platforms each consisted of a jacket, a module support frame, and topsides composed of modules. The jacket was an over-300-foot-high, four-legged structure that stood on the sea floor and rose above water level. Each leg of the jacket was permanently attached to the sea floor by piles. The module support frame was affixed to the top of the jacket. The topsides consisted of over 35 modules that were stacked atop the module support frame. The modules were large steel cubes that were fabricated onshore. Appendix A is a diagram showing 23 of the modules on the Brae B platform. In constructing the Brae A and Brae B platforms, as much of the fabrication and construction work as possible was done onshore because of the more difficult working conditions at the offshore platform sites.

The Brae B platform stands in approximately 325 feet of water. At the platform’s highest point, the top of the platform’s derrick is approximately 360 feet above sea level. The Brae B platform is one of the world’s largest, fixed, offshore platforms. The platform was designed to house a minimum of 250 workers during normal operations and had the capacity to handle over 70,000 barrels of liquid hydrocarbons and 400 million cubic feet of natural gas per day.

The Brae A platform (except for module 65, which was not completed and commissioned until January 1988) was completed in 1983, and the Brae B platform was completed in 1987. The Brae A and Brae B platforms are connected by two pipelines. One pipeline is used to carry natural gas from the Brae A platform for use on the Brae B platform. The other pipeline is used to transport liquid hydrocarbons from the Brae B platform to the Brae A platform.

The combined liquid hydrocarbon production of the Brae A and Brae B platforms is sent via the “Brae forties” 30-inch pipeline from Brae A to landfall in Scotland. An approximately 150-mile-long gas pipeline is being constructed to carry the Brae A and Brae B platforms’ natural gas production from Brae B to landfall in Scotland. The gas pipeline is scheduled to be completed in 1994.

Brae B Platform and the Plan for Exploiting the Brae B Reservoir’s Oil and Gas Deposits

The Brae B platform was designed to be utilized for drilling wells into the Brae B reservoir and processing the hydrocarbons produced from such wells. It is a dual purpose drilling and production platform. High winds and rough seas can prevail in the North Sea, and the Brae B platform was designed to allow drilling and production operations to be conducted under those adverse conditions.

The Brae B reservoir is a retrograde condensate gas reservoir in which the petroleum fluids exist in a state somewhat between a liquid and a gas. In the lower portions of the reservoir, the petroleum fluids, due to gravity, have a greater liquid content. The petroleum fluids in the upper portions of the reservoir exist in a more gaseous state. One of the characteristics of a retrograde condensate reservoir is that as the pressure in the reservoir is lowered, the gaseous petroleum fluids will condense or revert into a more liquid phase. The reverting fluids can then become entrapped in the reservoir rock, thereby reducing the amount of liquid hydrocarbons that can be recovered from the reservoir.

Extensive studies were conducted in devising the final plan for exploiting the Brae B reservoir and designing the Brae B platform. These were based on the geological and geophysical data previously collected and the prior information obtained from the drilling of exploratory wells. Mathematical models of the reservoir were created and used in evaluating the various proposed plans.

Under the final drilling plan formulated for the Brae B reservoir, a minimum of 15 wells would be drilled — 12 producing wells and 3 gas injection wells. The studies conducted had indicated that, unless the pressure within the Brae B reservoir was maintained during the course of drilling and producing hydrocarbons from the reservoir, a large percentage of the potentially recoverable liquid hydrocarbons would be lost. The reservoir’s pressure would decline as hydrocarbons were produced from the reservoir. Maintenance of the reservoir’s pressure to maximize the amount of liquid hydrocarbons recovered could most economically be accomplished by reinjecting into the Brae B reservoir through the gas injection wells gas produced from the Brae A and Brae B reservoirs.

The wells drilled from the Brae B platform into the Brae B reservoir have a vertical depth of approximately 12,500 feet. The Brae B reservoir generally has a producing interval or thickness of about 500 feet.

Regulatory Supervision by the United Kingdom’s Department of Energy and the Flaring of Oil and Gas

The final plan for exploiting the Brae B reservoir was required to be submitted to and approved by the United Kingdom’s Department of Energy (U.K. Department of Energy). The U.K. Department of Energy further exercised extensive regulatory supervision throughout the planning, construction, commissioning, and operation of the Brae B platform. Prior to beginning various stages of the platform’s construction and commencing actual operations onboard the platform, approval from the U.K. Department of Energy was required.

The U.K. Department of Energy generally would not permit large volumes of gas from the Brae B platform and similar offshore platforms to be flared or burned off. Normally, only limited amounts of gas were permitted to be flared on a continuous basis. Under certain emergency or unusual conditions, however, a large volume of gas might be flared for short periods without the U.K. Department of Energy’s consent.

The first two wells drilled on the Brae B platform were a production and a gas-injection well. The production well was completed and began producing hydrocarbons before the gas-injection well was completed. At that stage of the platform’s completion, the gas-injection equipment on the Brae B platform had not yet been commissioned. In that limited instance, the U.K. Department of Energy permitted the gas produced from the production well to be flared.

Only gas containing a fairly insignificant amount of liquid hydrocarbons was flared in the Brae B platform’s flare facility. The processing facilities onboard the main platform and the flare facility were designed to remove as much of the liquid hydrocarbons from the gas as practicable. Although the flare’s burner could physically burn liquid hydrocarbons, liquid hydrocarbons were never flared. The flare facility was not designed, nor intended, to be used for the flaring of large volumes of liquid hydrocarbons.

The flare facility is kept in a constant condition of readiness to flare large quantities of gas suddenly if the need arises. Gas cannot simply be vented into the atmosphere, because of the danger presented if a cloud of such gas were to settle around the Brae B platform. A small volume of gas is constantly flared to keep the so-called “pilot light” in the flare facility burning. During certain process trips or emergency shutdowns, it will also be necessary to flare a further amount of gas.

Perforation of a Well in General

After a well is drilled, in order to make it produce, the well must be perforated. Generally, perforation entails the piercing of the reservoir rock at one or more levels within the drill hole. Perforation is done at the perceived optimum levels of the reservoir formation to provide holes through which the reservoir’s hydrocarbons and other contents may flow.

Perforation is accomplished by lowering a perforation gun down the drill hole that fires a shaped explosive charge. An approximately 20-foot length of the drill hole is perforated each time the perforation gun is fired.

Two methods of perforation are utilized in perforating oil and gas wells: (1) The through-casing method, and (2) the through-tubing method. Under the older through-casing method, perforation is done while the drill hole is filled with heavy drilling mud. Such drilling mud exerts enough pressure to prevent fluids from the reservoir from flowing up the well. All the estimated drill hole channels are perforated, and the well is completed for production of oil and gas. The “Christmas tree” is then installed, and the drilling mud is pumped out of the drill hole. The Christmas tree is a vertical assembly of pressure control valves and gauges that controls the flow from the well. If a subsequent well test demonstrates that the required amounts of oil and gas are not being produced, it will then be necessary to make further perforations.

The newer through-tubing method was developed as a result of research work done in the 1950s. Such research had indicated that oil and gas flow from the reservoir into the well bore was often considerably improved if the well were allowed to flow immediately upon perforating. The act of perforating creates debris of crushed rock and metal, which can lodge in the channel created in the reservoir rock by perforation. If the reservoir’s fluids are allowed to flow up the well bore immediately upon perforating, such flow will clean out and remove the debris before it has a chance to compact and become lodged in the perforation channel.

Under the through-tubing method, perforation is done after the heavy drilling mud has been pumped out of the drill hole. Where a well is perforated utilizing the through-tubing method, the reservoir’s fluids commence flowing up the drill hole immediately following initial perforation of the well. Where the through-tubing method is utilized, typically the “Christmas tree” will be installed prior to perforating the well. Due to the geological conditions existing with respect to the Brae B reservoir, the through-tubing method was employed in perforating the Brae B platform’s wells. Since the early 1970s, the through-tubing method, although more expensive than the through-casing method, has been the most prevalent method of perforation utilized in perforating oil and gas wells.

Upon initial perforation of a well utilizing the through-tubing method, it is necessary to measure and test the production coming up that well. If such production does not meet required levels, additional perforations may have to be made in the drill hole. With respect to the wells on the Brae B platform, the perforation and testing process has been a matter of trial and error and can take several days.

To test and measure the well’s production, certain equipment is required. A test separator is needed to separate the well’s production into its gas, oil, and water components and perform measurements of volume and pressure. During the time such measurements and test samples are being taken, some means must exist for disposing of the production flowing up the well. On the Brae B platform, oil was pumped to shore, gas was reinjected into the reservoir, and water was treated and dumped into the ocean.

Relation of the Disputed Modules and Their Equipment to the Drilling and Completion of the Brae B Platform Wells

A general description of the equipment inside the modules in dispute and the intangible costs petitioner incurred with respect to each module for 1984 and 1985 are as follows:

1984 Intangible cost 1985 Intangible cost

Module No. Equipment description Structural Equipment installation Total Structural Equipment installation Total

3 Separation $121,849 $241,382 $363,231 $713,204 $327,361 $1,040,565

4 Compressor and oil export 248,404 169,932 418,336 881,542 218,880 1,100,422

5 NGL (natural gas liquids) recovery and refrigeration 120,402 260,564 380,996 683,359 379,379 1,062,738

6 Gas injection compressors 265,198 446,619 1,167,988 290,002 1,457,990

16 Gas injection compressors 260,969 178,528 439,497 1,156,831 1,444,063

65 Brae A export compressor 72,954 61,492

The structural costs are those intangible costs incurred in the construction, transportation, and installation of each module. The equipment installation costs are those intangible costs incurred to install the equipment contained in each module. No information was provided regarding the allocation of module 65’s total intangible costs to structural costs and equipment installation costs.

Modules 3, 4, 5, 6, and 16 physically support modules and equipment located above them on the Brae B platform, which are, for the most part, used in the drilling of wells and for the preparation of such wells for production. Modules 3, 4, 5, and 6 physically support modules 13, 14, 15, and 16. Drilling equipment located on top of modules 13, 14, 15, and 16 must be at a particular location or elevation on the platform. Such drilling equipment would include the pipe rack, the well logging unit, the cherry picker crane, and the gravity feed water tank. If modules 3, 4, 5, 6, and 16 were not located on the Brae B platform, other structural means would have to be devised to physically support and properly position modules 13, 14, and 15 and the drilling equipment located on them and located on module 16.

Perforation and testing were necessary in preparing the wells drilled on the Brae B platform for production. As part of the perforation and testing process, oil and gas must be produced from the particular Brae B well undergoing perforation to obtain the following information: (1) The gas/oil ratio, and (2) the amount of stabilized oil being produced (i.e., the well’s daily production rate). Without such information, it cannot be determined whether the perforation operation is complete. The gas/oil ratio of the production from the well is measured by the test separator located in module 3. After such production has been fully stabilized by the main separation train located in modules 3 and 4, the well’s daily production rate can be determined utilizing the metering system located downstream from the main separation train. Such metering equipment records the liquid hydrocarbons exported off the platform.

In carrying out the perforation and testing process, it was necessary to have some means of dealing with the large amounts of gas, oil, and water that would be produced on the Brae B platform. When a well was initially perforated, fluids and gas from that well were immediately produced on the Brae B platform. Thereafter, each time another level within the drill hole was perforated, the well would be allowed to flow to remove the debris from perforating. In addition, testing and measurement of the well’s production required permitting the well to flow for a certain period of time. For instance, with respect to the first well drilled on the Brae B platform, production from that well was allowed to flow to the platform’s test separator for a 32-hour period after the initial perforation. Ultimately, a total of eight perforations was made. Each time an additional perforation was made, the well was allowed to flow to the test separator for a period ranging from 10 minutes to 2 hours.

After leaving the test separator in module 3, oil, gas, and water produced during the perforation and testing process go directly to the main separation train located in modules 3 and 4. A three-stage main separator is located in module 3, along with the test separator. The main separator located in module 3 separates the oil, gas, and water produced during perforation and testing of a well and during normal production from that well. The equipment located in module 4 on the Brae B platform would: (1) Recycle the gas which still contains liquid back to the main separator in module 3 for removal and measurement of additional liquids, and (2) export the stabilized oil for sale.

During perforation and testing operations, the water produced was separated from the oil and gas, treated to regulatory specifications, then dumped back into the ocean. The oil produced was exported for sale. Before oil was exported from the Brae B platform, it was stabilized in the main separation train; i.e., separated from the water and gas. The gas produced is subjected to additional processing prior to being reinjected into the Brae B reservoir.

The NGL equipment located in module 5 removes the butane and propane from the natural gas produced on the Brae B platform. The butane and propane removed are combined with the oil production and exported off the platform via the oil export compressor in module 4. In addition to removing the butane and propane, the NGL equipment also removes excess water from the natural gas prior to the gas being sent to the injection compressors located in modules 6 and 16. Removal of the water prevents the formation of hydrates, which are essentially like snowflakes, consisting of water and a little methane gas, in the gas-injection equipment located in modules 6 and 16. Unless such excess water was removed, hydrates could form and freeze up the gas injection equipment. If the injection equipment located in modules 6 and 16 became nonoperational, all perforation and testing and production activities aboard the Brae B platform would have to be halted.

The injection compressors in modules 6 and 16 on the Brae B platform inject gas into the reservoir through injection wells. The compressor equipment in module 65 on the Brae A platform provides gas used for injection into the Brae B reservoir and gas used as fuel to drive electric generators that are the source of power for drilling operations on the Brae B platform. Drilling operations on the Brae B platform commenced on November 19, 1987. Actual drilling for hydrocarbons commenced on January 1, 1988, and January 19, 1988. Initially, the power used for such drilling operations came from diesel-powered generators located on the Brae B platform. On January 23, 1988, module 65 on the Brae A platform was commissioned and used to deliver Brae A gas to the Brae B platform. Part of the Brae A gas delivered was used to power the Brae B platform’s main generators. Drilling operations on the platform were then continued using the Brae A gas. Brae A gas was used to power the Brae B platform and its ongoing drilling operations during the period from January 23, 1988, until sometime in 1991, when Brae B gas began to be used for power production purposes. At that time, the Brae A gas that previously would have been used as fuel was injected into the Brae B reservoir. Nine or more wells were drilled using Brae A gas as a power source.

Petitioner’s Extraction of Sulphur

Petitioner owned working interests in certain oil and gas leases in the Jay-Little Escambia Creek field (Jay field) located in Escambia County, Alabama, and Santa Rosa and Escambia Counties, Florida, and in the Big Escambia Creek field (bec field) located in Escambia County, Alabama. From wells on these leases, petitioner extracted liquid hydrocarbons, hydrocarbon gases, nonhydrocarbon gases such as hydrogen sulfide, carbon dioxide, and nonhydrocarbon liquids such as brine water.

When brought to the surface, all of the items produced from the well are physically commingled. The gaseous effluent from the wells is referred to as “sour gas”; i.e, gas containing both natural gas and hydrogen sulfide gas.

Sour gas cannot be used as a fuel without first removing the hydrogen sulfide and carbon dioxide. Hydrogen sulfide is a poisonous, highly corrosive gas which cannot be vented into the atmosphere without serious harmful effects. Sour gas cannot be transported through gas pipelines because the corrosive nature of the hydrogen sulfide gas would damage the pipeline. Further, the hydrogen sulfide gas would damage the combustion equipment that might be used in burning the sour gas. In addition, the combustion of hydrogen sulfide gas produces sulphur dioxide. Sulphur dioxide is a toxic substance subject to control under air quality laws.

The well effluents from the Jay and BEC fields are treated in facilities adjacent to each field’s wells. Hydrogen sulfide is not transported far from the well because of the hazards involved. The well effluent is initially treated in a separation system which uses gravity to separate the effluent into brine water, sour crude oil, and a sour gas stream containing natural gas, hydrogen sulfide, and carbon dioxide. The brine water is reinjected into the wells.

The separated sour crude oil undergoes further treatment within the oil stabilization system, a pressurized vessel in which heat vaporizes and removes more of the dissolved sour gas. The oil stabilization system also reduces the vapor pressure of the crude oil to a level low enough that the crude oil can be stored and transported in atmospheric tanks and tank trucks.

The sour gas streams from the separation system and the oil stabilization system, containing both natural gas and hydrogen sulfide, are combined and further treated in the acid gas removal system. The acid gases (hydrogen sulfide and carbon dioxide) are separated from the natural gas through an absorption process. In a vessel called a contractor, an amine solution such as sulfinol is added to the sour gas. The amine solution absorbs the hydrogen sulfide and carbon dioxide, and natural gas flows out of the top of the contractor. The separated natural gas is then transported through natural gas pipelines for use or sale by petitioner.

In both the Jay field and BEC field sulphur recovery plants, the acid gas is then separated from the amine solution and passed into a multistage Claus sulphur recovery system. The Claus method of sulphur recovery is based on the “Claus reaction”. In the Claus reaction, a chemical reagent, sulphur dioxide, is added to hydrogen sulfide. In the ensuing chemical reaction between the sulphur dioxide and hydrogen sulfide, sulphur vapor and water will be released.

The actual sulphur recovery processes employed in the Jay field plants and BEC field plants are very similar. In the initial step, some of the hydrogen sulfide gas is converted into sulphur dioxide by controlled combustion with air in a reaction furnace. In the subsequent steps, more of the hydrogen sulfide is converted to elemental sulphur as a result of a controlled chemical reaction with the sulphur dioxide produced in the first step. The carbon dioxide is vented into the atmosphere. The Claus sulphur recovery plants convert more than 96 percent of the hydrogen sulfide into elemental sul-phur. The sulphur is then condensed and stored until sold. The Jay field plants and BEC field plants differ in their respective reaction furnace and initial cooling or condensing processes. See appendices B and C to this opinion.

At the Jay field sulphur recovery plants, all of the hydrogen sulfide is processed through the reaction furnace. The reaction furnace causes hydrogen sulfide to combine with oxygen, thereby yielding sulphur vapor, sulphur dioxide, water vapor, and unreacted hydrogen sulfide. The gas stream, which exits the reaction furnace, is then cooled in a two-stage condensing process which yields liquid sulphur. The liquid sulphur and gas streams are separated by gravity. The liquid sulphur is stored in heated condition until sold. The gas stream which exits the initial condenser process is reheated and then enters the Claus reactor. In the Claus reactor, the mixtures of hydrogen sulfide and sulphur dioxide are combined in the presence of a catalyst to yield sulphur vapor and water vapor. A portion of the hydrogen sulfide and sulphur dioxide passes through the Claus reactor unreacted. The gas stream, which exits the Claus reactor, is cooled in a cooling and condensation process which yields liquid sul-phur. The liquid sulphur and gas stream are separated by gravity, and the liquid sulphur is stored in heated condition until sold. The remaining gas stream is again preheated and routed through the Claus reactor and another condensing process two times further to recover additional sulphur.

At the BEC field plants, one part of the hydrogen sulfide bypasses the reaction furnace, and another part of the hydrogen sulfide is combined with oxygen in the reaction furnace and completely oxidized to yield sulphur dioxide and water. The hot sulphur dioxide exiting the reaction furnace is cooled in a single-stage cooling process. Little or no condensation of sulphur vapor occurs during this cooling process. The hydrogen sulfide which bypassed the reaction furnace is slightly heated and then mixed with the sulphur dioxide that exits the cooling process. The subsequent Claus reactor and condensation processes at the BEC field plants are identical to those at the Jay field plants described above.

At both the Jay and BEC plants, before the gas stream enters the Claus reactor it is heated from approximately 300 degrees Fahrenheit to 400 degrees Fahrenheit. This is done to maintain the temperature of the gas stream in the Claus reactor above the dew point for sulphur.

The primary products from the Jay and BEC fields have been oil and natural gas. Sulphur has been recovered from hydrogen sulfide and sold as a byproduct of the processing facilities since the fields were in operation.

The basic Claus sulphur recovery process was developed in England around 1890 but did not become economically feasible until modified by work in Germany in 1937. The first commercial plant in the United States to use the modified Claus method was placed in operation in 1944. Claus sulphur recovery plants, however, were not economically attractive investments until the value of sulphur began to rise significantly in the 1960s. By 1970, an oversupply of sulphur seriously depressed prices, but the sulphur market recovered and the price of sulphur rose dramatically in the late 1970s and early 1980s.

Despite dramatic increases in construction and operating costs of Claus sulphur recovery facilities since 1968, the sul-phur recovery industry has continued to grow, partly because air-pollution control laws mandate the recovery of sulphur from hydrogen sulfide removed from oil and gas wells.

The other major source of sulphur for commercial use is produced by the Frasch mining method. The Frasch sulphur mining industry was developed in the 1920s. Under the Frasch method, superheated water is injected into underground sulphur deposits to melt the sulphur, which is then brought to the surface through sulphur wells. Until 1982, the Frasch sulphur mining industry was the dominant source of the world’s sulphur. Since that time, however, the amount of sulphur recovered from hydrogen sulfide utilizing the Claus method has been greater than sulphur recovered utilizing the Frasch method.

Petitioner’s Revenues and Expenses From Its Operations in the Jay and BEC Fields

The entire Jay field is unitized under forced unitization orders by the States of Alabama and Florida. In the BEC field, there are eight producing well units or “properties”. Each property participates under a voluntary unitization agreement in a single unit plan of operation. All the mineral interests covered by each unitization agreement are in the same mineral deposit or in two or more mineral deposits, the joint development of which is logical from the standpoint of conservation, convenience, economy, or geology, and are in tracts of land which are contiguous or in close proximity.

With respect to petitioner’s working interest in the Jay field during 1984 and 1985, revenues were generated and expenses were incurred as follows:

1984 1985

Gross sales income—

Sulphur $2,143,569 $2,093,299

Oil 83,197,988 59,918,603

Gas 3,877,809 3,631,692

Expenses—

Depreciation 11,904,130 12,009,943

Intangible drilling costs 118,746 462,622

Lease operating expenses 15,409,730 12,968,911

Nitrogen tertiary injection 5,215,267 5,514,960

Overhead 811,666 910,802

Severance taxes 7,630,511 1,448,593

Windfall profit taxes 2,702,621 (38,388)

With respect to petitioner’s working interests in the eight well units or “properties” in the BEC field, during 1984 and 1985, revenues were generated and expenses were incurred, as follows:

1984 1985

Dinks Farm

Gross sales income—

Sulphur $45,081 $56,167

Oil 99,249 100,862

Gas 638,334 47,156

Expenses—

Depreciation 1,085 918

Intangible drilling costs

Lease operating expenses (89,378) 10,839

Overhead (83,919) 13,682

Plant facility costs 41,816 13,112

Severance taxes 72,321 13,454

Windfall profit tax 26,058 19,663

Forte 10-7

Gross sales income—

Sulphur 189,867 413,481

Oil 525,347 878,039

Gas 187,033 373,800

Expenses—

Depreciation 4,798 3,018

Intangible drilling costs

Lease operating expenses 31,622 83,541

1984 1985

Overhead 68,775 107,989

Plant facility costs 48,206 106,940

Severance taxes 68,146 114,040

Windfall profit tax 138,737 171,915

Helton GU-1

Gross sales income—

Sulphur 13,480 15,795

Oil 27,301 21,819

Gas 9,191 11,959

Expenses—

Depreciation 82 17

Intangible drilling costs -

Lease operating expenses 1,905 3,362

Overhead 3,697 3,732

Plant facility costs 2,670 3,183

Severance taxes 3,477 3,032

Windfall profit tax 7,239 4,252

Philyaw 8-1

Gross sales income—

Sulphur 354,566 346,356

Oil 797,467 720,649

Gas 274,894 290,544

Expenses—

Depreciation 7,377 4,620

Intangible drilling costs -

Lease operating expenses 48,741 92,648

Overhead 101,391 107,459

Plant facility costs 76,239 87,176

Severance taxes 102,190 92,613

Windfall profit tax 210,500 140,870

St. Regis 9-4 / 7

Gross sales income—

Sulphur 58,048 140,884

Oil 143,349 245,064

Gas 48,581 125,411

Expenses—

Depreciation 13,211 13,066

Intangible drilling costs 7,158 577

Lease operating expenses 11,266 26,941

Overhead 26,693 36,443

Plant facility costs 13,356 32,837

Severance taxes 18,209 33,456

Windfall profit tax 37,303 48,143

Scott Paper GU-7

Gross sales income—

Sulphur 55,182 81,912

Oil 157,101 164,582

Gas 47,596 72,175

Expenses—

1984 1985

Depreciation 1,933 1,216

Intangible drilling costs 117 (583)

Lease operating expenses 38,424 17,344

Overhead 56,697 20,946

Plant facility costs 13,885 20,464

Severance taxes 19,866 21,659

Windfall profit tax 40,692 32,744

Scott Paper 3-10

Gross sales income—

Sulphur 47,259 41,926

Oil 102,797 76,323

Gas 45,737 33,900

Expenses—

Depreciation 404 369

Intangible drilling costs

Lease operating expenses 10,199 10,593

Overhead 17,629 12,381

Plant facility costs 10,461 9,770

Severance taxes 13,901 9,978

Windfall profit tax 27,019 14,879

Scott Paper 30-1

Gross sales income—

Sulphur 145

Oil

Gas 137

Expenses—

Depreciation 12,520 11,214

Intangible drilling costs

Lease operating expenses 13,769 (10,454)

Overhead 21,754 (3,624)

Plant facility costs 15

Severance taxes 11

Windfall profit tax

OPINION

IDC Deductions

Section 263(c) and section 1.612-4, Income Tax Regs., promulgated thereunder provide that taxpayers have the option to deduct, rather than capitalize, their “intangible drilling and development costs”.

Section 1.612-4, Income Tax Regs., in pertinent part, provides 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.
(c) Nonoptional items distinguished. (1) Capital items: The option with respect to intangible drilling and development costs does not apply to expenditures by which the taxpayer acquires tangible personal property ordinarily considered as having a salvage value. Examples of such items are the costs of the actual materials in those structures which are constructed in the wells and on the property, and the cost of drilling tools, pipe, casing, tubing, tanks, engines, boilers, machines, etc. The option does not apply to any expenditure for wages, fuel, repairs, hauling, supplies, etc., in connection with equipment, facilities, or structures, not incident to or necessary for the drilling of wells, such as structures for storing or treating oil or gas. These are capital items and are recoverable through depreciation.

The idc provisions of the regulations have been interpreted and applied in accordance with the direction that “Congress favors a liberal interpretation of the regulation.” Exxon Corp. v. United States, 212 Ct. Cl. 258, 547 F.2d 548, 555 (1976); Gulf Oil Corp. v. Commissioner, 87 T.C. 324, 342-343 (1986); Standard Oil Co. (Indiana) v. Commissioner, 77 T.C. 349, 386-387 (1981); Texaco, Inc. v. United States, 598 F. Supp. 1165 (S.D. Tex. 1984). Their history has been detailed at length in Exxon Corp. v. United States, supra at 553—555, 563-564.

In Standard Oil Co. (Indiana) v. Commissioner, supra at 390-391, we specifically rejected respondent’s attempt to have us narrowly construe the “incident to and necessary” language of the regulations, and stated:

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

In the instant case, the nonmaterial costs of petitioner in dispute are those associated with the construction, transportation, and installation of modules 3, 4, 5, 6, and 16 on the Brae B platform and module 65 on the Brae A platform. Petitioner’s claimed IDC deductions do not include the acquisition costs of any materials or equipment in the modules. However, the disputed deductions include the intangible costs incurred in installing certain equipment inside the modules. The parties agree there is no salvage value issue with respect to petitioner’s claimed IDC deductions. They disagree as to whether such costs were “incident to and necessary for the drilling and development” of the Brae B platform’s wells within the meaning of the regulations.

From the outset, petitioner has acknowledged that the modules and equipment in dispute served dual functions: Well drilling and development and normal production operations. Petitioner contends that the claimed IDC deductions are allowable, because the costs incurred were incident to and necessary for the drilling and development of the Brae B platform wells, for production of oil and gas. Petitioner maintains that modules 3, 4, 5, 6, and 16 on the Brae B platform physically support certain other modules and drilling equipment, thereby allowing such drilling equipment to be located properly for efficient drilling operations. Petitioner further asserts that the equipment contained in modules 3, 4, 5, 6, and 16 was necessary for the perforation and testing processes needed to prepare the Brae B platform’s wells for production. Lastly, petitioner notes that module 65 on the Brae A platform supplied gas to provide power for the drilling and development operations onboard the Brae B platform.

Respondent does not dispute that the modules and equipment in them were utilized to some extent in the drilling and development of the Brae B platform’s wells for production of oil and gas. Respondent, however, argues that for the expenditures to meet the “incident to and necessary” test, the primary purpose of the expenditures must be for well drilling and development, as opposed to production. Respondent maintains that the primary purpose of the expenditures was to increase the profits of the parties participating in the North Brae venture and points out that gas injection was utilized in exploiting the oil and gas deposits, in order to maximize the liquid hydrocarbons recovered from the Brae B reservoir. Respondent further argues that alternative means could have been utilized in carrying out the well drilling and development work, that the disputed modules and equipment in them were merely a “convenience”, rather than “necessary”, and that the costs in issue fail to satisfy the “incident to and necessary” test of the regulations.

We reject respondent’s contention that a “primary purpose” requirement must be met under the “incident to and necessary” test of the regulations. In doing so, we note that the regulations themselves contain no suggestion whatsoever of such a requirement. Indeed, the regulations give as examples of expenditures qualifying for the IDC option certain items, such as roads and derricks, which obviously may be used extensively in the production phase of a particular oil and gas property for the entire life of the well, which far exceeds the drilling and development period. See sec. 1.612-4(a)(2) and (3), Income Tax Regs. Such an interpretation of the regulations is unwarranted and has been effectively put to rest by our prior holding in Standard Oil Co. (Indiana) v. Commissioner, supra. In that case, we recognized that the offshore drilling platforms involved therein would be used for a relatively short period of their useful lives for drilling, as opposed to production, purposes. Respondent relies on certain language in Producers Chemical Co. v. Commissioner, 50 T.C. 940, 962 (1968), to support imposing a primary purpose requirement. In that case, the issue raised was whether fracturing costs incurred with respect to certain old oil wells qualified to be deducted as IDC. A careful reading of our opinion discloses that the term “primarily” was employed in summarizing the evidence that had been offered on the factual issue presented, not in promulgating an additional legal requirement to be met under the “incident to and necessary” test of the regulations. Resolution of the case turned on whether the expenditures were for opening up new zones of production or for increasing the old wells’ existing production. The taxpayer’s experts had testified that the work in question was done “primarily to open up new zones of oil production that had not been previously producing.”

Respondent acknowledges that modules 3, 4, 5, and 6 on the Brae B platform physically support modules 13, 14, 15, and 16, and that drilling equipment is located on top of modules 13, 14, 15, and 16. Respondent does not dispute that certain drilling equipment, such as the pipe rack, well logging unit, cherry picker crane, and gravity-feed water tank must be in a particular position to facilitate drilling operations. Respondent argues, however, that her contended-for primary purpose requirement, which we reject, is not met. Respondent maintains that the use of the modules as support was simply “incidental to the overall objective of building a facility that is efficient and cost effective.” Respondent notes that the participants in the North Brae venture originally had considered building separate drilling and production platforms to exploit the Brae A reservoir. As it was less costly to build a single larger platform, rather than build two separate platforms, the Brae A platform was built as a combined drilling and production platform. Respondent contends that the decision to build the Brae B platform as a single drilling and production platform, and not as two separate platforms, was based upon economics rather than any inherent structural requirements. Respondent points out that if separate drilling and production platforms had been built, the modules would not have been needed to support the drilling equipment.

Although respondent places great emphasis on the possibility that two separate platforms could have been built, the fact remains that a single drilling and production platform was what was actually built. In determining whether the intangible costs in question qualify to be deducted as IDC, we examine the actual offshore platform constructed and the actual drilling and development work required. The application of the “incident to and necessary” test of the regulations is a fact question that is to be resolved based on the facts and circumstances presented in the particular case. It serves no purpose to speculate, as respondent does in the instant case, about different and remote factual situations wherein the expenditures in dispute would not be necessary.

The Brae B platform was built as a combined drilling and production platform. If these modules did not exist to offer structural support, other means would have been found to support the modules and drilling equipment located above them. Although other means of physical support, such as temporary scaffolding, might technically be possible, such other means of support would not have been very feasible or practical and would have been far more costly. Indeed, on cross-examination, one of respondent’s experts testified that he would not have designed tbp Brae B platform any differently for purposes of conducting drilling. He stated that he had no argument at all with the design of the platform. The intangible structural costs of modules 3, 4, 5, 6, and 16 meet the “incident to and necessary” test of the regulations.

Module 65 on the Brae A platform was used to supply the gas used in conducting Brae B platform’s drilling operations during approximately a 3-year period. Nine or more wells were drilled during that period. Respondent contends that module 65’s primary purpose was to supply the Brae A gas used for injection into the Brae B reservoir. As indicated above, however, we refuse to read a primary purpose requirement into the “incident to and necessary” test under the regulations. Respondent further argues that the gas supplied by module 65 was unnecessary to the Brae B platform’s drilling operations, because drilling could have been accomplished using more expensive diesel fuel as a power source. The intangible costs incurred with respect to module 65 were incident to and necessary for the drilling of the Brae B platform’s wells, and we so hold. They qualify to be deducted as IDC.

This leaves the intangible costs incurred with respect to installing the equipment contained in modules 3, 4, 5, 6, and 16 on the Brae B platform. The parties agree that in performing the perforation and testing needed to complete a well for production of oil and gas, some means must exist for disposing of the oil, gas, and water produced from a well.

Petitioner offered testimony from four expert witnesses who had extensive experience with the design and operation of the Brae B platform. R.J. Pready is a mechanical engineer and was employed by the designing and engineering firm that designed the Brae A and Brae B platforms. From 1984 through 1988, he worked on the Brae B platform project on a full-time basis. During 1984 and 1985, he was one of two engineering managers responsible for the design of all of the Brae B platform’s topside modules.

Allan Kennedy is a petroleum engineer who has considerable experience in the drilling and production of oil and gas produced from offshore platforms. From 1985 through approximately 1991, he was employed at Marathon Oil with the title of production reporting supervisor. As part of his first duties with Marathon in 1985, he designed the computerized production reporting system that accounted for all hydrocarbons produced onboard the Brae B platform. He was familiar with the provisions of United Kingdom’s petroleum laws affecting the platform’s operations. Prior to being employed with Marathon Oil, he had worked at the U.K. Department of Energy for approximately 5 years.

John A. Turley is a petroleum engineer with extensive experience in offshore drilling. In 1975, he was employed by Marathon Oil and in 1979 was sent to London and worked as the drilling design manager for North Brae development. From 1981 to 1984 he served as operations manager for Marathon Oil U.K., Ltd., in Aberdeen, Scotland. From 1984 through 1987, he served as coordinating manager and production manager, responsible for all of Marathon Oil’s United Kingdom production.

Larry L. Yoho is a petroleum engineer who has specialized in reservoir engineering since joining Marathon Oil in 1974. From 1988 through 1991, he worked as Marathon’s engineering manager with oversight over all north, south, and central Brae fields. His duties with respect to the Brae B platform primarily concerned reservoir management and platform operations.

Petitioner’s expert witnesses testified that with respect to the Brae B platform, no other practicable means exist for disposing of the oil, gas, and water produced during perforation and testing. Mr. Pready testified that while the Brae B flare facility’s burner can physically burn liquid hydrocarbons, the flare facility was never designed, nor intended, to be used for flaring a large volume of liquid hydrocarbons. He stated that such flaring of liquid hydrocarbons would create a number of problems which would require major design changes to the Brae B platform’s pipework systems and controls. He further testified that if the flare facility were used to flare the large volume of liquid hydrocarbons typically produced during the testing and perforation of a well, there would be a “volcano effect” and that large unburned slugs of oil would come out of the flare and fall into the ocean.

With respect to the gas produced during the production and testing process, Mr. Kennedy testified that only limited flaring of gas on the platform is allowed under United Kingdom law. He and petitioner’s other experts were of the opinion that the only feasible means of disposing of the gas was to process and reinject it into the Brae B reservoir since no gas pipeline had yet been built.

Mr. Kennedy elaborated that, on the Brae B platform, a well undergoing testing typically would be capable of producing gas at the rate of between 50 and 100 million cubic feet of gas a day. He testified that a well undergoing testing would be allowed to produce at that rate for an average period of 12 hours. In the case of an injection well, however, he stated that between 200 and 250 million cubic feet of gas could be produced during the course of testing the well’s “injectivity” over several days. As the typical flare consent issued by the U.K. Department of Energy allowed only 10 million cubic feet a day to be flared over a 6-month period, substantially all of which is already needed for flaring for other purposes, flaring the gas produced from wells undergoing perforation and testing would be legally impossible. He was further of the opinion that the U.K. Department of Energy generally would not consent to flaring the gas produced during perforation and testing of the Brae B platform’s wells because such flaring would be a needless waste of the United Kingdom’s natural resources.

On brief, respondent argues that Mr. Kennedy was incorrect and that United Kingdom law would permit the gas to be flared because such flaring would be necessary to maintain the wells’ flow. In making this argument, respondent relied on subparagraph 7 of paragraph 21 of the United Kingdom’s Petroleum and Submarine Pipe-Lines Act of 1975. Under this provision, the U.K. Department of Energy’s consent is not required for flaring necessary to maintain the flow of petroleum from any well, in the case of the occurrence of an unforeseen event where there is no time to deal with such event other than by flaring. It would, however, appear to be foreseeable that, during the course of perforating and testing wells, a large amount of gas would be produced and that some means of disposing of that gas would be needed.

Respondent offered the testimony of two expert witnesses, Forrest A. Garb and Donald V. Nicol. Mr. Garb is a petroleum engineer and had worked for a large oil company for about 5 years during the 1950s. Since 1957, he has worked for two petroleum engineering consulting firms. His consulting work has chiefly involved the use of computers to perform evaluations of oil and gas properties. Mr. Nicol is a mechanical engineer. His primary experience has been in the production, processing, storage, and transportation of natural gas.

Mr. Garb and Mr. Nicol were of the opinion that none of the equipment contained in the modules was necessary for perforation and testing of the Brae B platform’s wells. They testified that only the test separator and oil export compressor onboard the Brae B platform would actually be used in perforation and testing. However, they opined that the test separator and oil export compressor on the platform, although convenient, were not necessary because perforation and testing could be accomplished by bringing alongside the Brae B platform a portable test separator located onboard a barge. They testified that the oil and gas produced during the perforation and testing process could be disposed of through flaring in the Brae B platform’s flare facility. They, however, seemed to be unaware of the restrictions on flaring of gas imposed under United Kingdom law as previously discussed. They also were not aware of the problems attendant to flaring the oil in the Brae B platform’s flare facility which Mr. Pready had noted.

Petitioner’s expert witnesses vehemently disagreed with respondent’s experts and were of the opinion that bringing a barge alongside the platform was not a viable option. They pointed to a number of hazards and safety problems that would be created. During rough sea conditions, perforation and testing would have to cease because of the danger presented were the barge to slam into the platform. Mr. Pready noted that moving the barge away from the platform could be difficult if sudden bad weather arose. Strict radio silence onboard and near the platform must be maintained when the perforation gun is being loaded and lowered down a well, as a radio transmission might accidentally detonate the shaped explosive charge. Moreover, if a portable test separator on a barge were brought alongside the platform, temporary lines would have to be installed to carry the production from the well undergoing testing to the barge-located test separator. Petitioner’s expert witnesses testified that employing such temporary, flexible lines to carry large amounts of oil and gas would present unacceptable hazards during rough sea conditions. Indeed, one of respondent’s experts, Mr. Garb, acknowledged that in the situation he related concerning the use of a test separator on a barge, the testing had been done for only an 8- to 10-hour period. Mr. Garb further stated that he did not dispute that having the equipment onboard the platform would be the most practical option.

Petitioner’s expert witnesses were more persuasive than respondent’s experts and were more knowledgeable about the Brae B platform’s operations. As a minimum of 15 wells would be drilled into the Brae B reservoir, utilizing the test separator installed in module 3 would be far preferable to employing a portable test separator located onboard a barge. Utilizing a test separator permanently installed on the platform avoids the significant hazards that would be entailed in bringing a barge alongside the Brae B platform. Respondent’s experts were unaware that the United Kingdom’s laws essentially prohibited flaring the gas produced during perforation and testing. Neither were they aware of the problems of flaring large quantities of oil in the platform’s flare facility.

We find that the intangible costs incurred in installing the equipment contained in modules 3, 4, 5, 6, and 16 onboard the Brae B platform qualified to be deducted as IDC. Such equipment was incident to and necessary for the development of the wells drilled from the Brae B platform.

Whether Petitioner’s Extraction of Sulphur Qualifies as “Mining”

Section 611(a) generally provides that in the case of mines, and oil and gas wells, there shall be allowed as a deduction a reasonable allowance for depletion. Under section 613(a), this allowance is prescribed as a specified percentage (22 percent for sulphur) of “gross income from the property”, not to exceed 50 percent of the taxable income from the property, computed without the allowance. As relevant here, “gross income from the property” is defined in section 613(c)(1) as “the gross income from mining”; “mining”, in turn, is defined in section 613(c)(2), to include the extraction of ores or minerals from the ground plus “the treatment processes considered as mining described in paragraph (4) (and the treatment processes necessary or incidental thereto)”.

The parties agree that the treatment processes considered as mining pertinent to the sulphur extracted in the instant case are those set forth in section 613(c)(4)(D). Section 613(c)(4)(D) relates to “ores or minerals which are not customarily sold in the form of the crude mineral product” and lists the following processes:

crushing, grinding, and beneficiation by concentration (gravity, flotation, amalgamation, electrostatic, or magnetic), cyanidation, leaching, crystallization, precipitation (but not including electrolytic deposition, roasting, thermal or electric smelting, or refining), or by substantially equivalent processes or combination of processes used in the separation or extraction of the product or products from the ore or the mineral or minerals from other material from the mine or other natural deposit * * *

Thus, those processes or combinations of processes that are substantially equivalent to certain specified mining processes will also be treated as mining processes, to the extent that they are applied for the purpose of separation or extraction of minerals from other material extracted from the mine or natural deposit. Sec. 1.613-3(f)(4), Income Tax Regs.

Finally, section 613(c)(5) excludes from mining certain enumerated processes as follows:

(5) TREATMENT PROCESSES NOT CONSIDERED AS MINING. — Unless Such processes are otherwise provided for in paragraph (4) (or are necessary or incidental to processes so provided for), the following processes shall not be considered as “mining”: electrolytic deposition, roasting, calcining, thermal or electric smelting, refining, polishing, fine pulverization, blending with other materials, treatment effecting a chemical change, thermal action, and molding or shaping.

In Barton Mines Corp. v. Commissioner, 53 T.C. 241, 254 (1969), affd. in part, revd. and remanded 446 F.2d 981 (2d Cir. 1971), we exhaustively analyzed the legislative history and provisions of section 613(c), and stated as follows:

Our study convinces us that although section 613(c) lists processes which shall and shall not be considered as mining, a mechanical application of the statutory language was not intended; we do not believe that Congress meant for us to embark upon the task of determining which of opposing parties’ technical descriptions of a disputed process more precisely fits the statutory term. Rather, it is necessary to determine the function served by the particular process in question. For example, a process that is “substantially equivalent” to a process enumerated in section 613(c)(4)(D) will be considered as mining only if it is “used in the separation or extraction of the product or products from the ore or the mineral or minerals from other material from the mine or other natural deposit.” And the processes listed in section 613(c)(5) are not to be considered as nonmining processes if they are “necessary or incidental” to mining processes. The importance of the function served by a process is also recognized in the regulations. See, e.g., sec. 1.613 — 3(f)(4) and (g)(2), Income Tax Regs. [Fn. ref. omitted.]

In Union Carbide Corp. v. Commissioner, 75 T.C. 220 (1980), affd. per curiam on another issue 671 F.2d 67 (2d Cir. 1982), we dealt specifically with the question of whether a solvent extraction process employed by a taxpayer to extract tungsten and vanadium qualified as a “mining process” because it was substantially equivalent to the enumerated mining process of precipitation. The minerals previously had been leached out of low grade ores and were in liquid solution. In the solvent extraction process, an organic chemical reagent was added which reacted with the desired minerals to create an organic chemical liquid. The organic chemical liquid containing the desired minerals was then separated from the rest of the residual aqueous solution using a semipermeable membrane which would allow the aqueous liquid to flow through but not the organic chemical liquid. In Union Carbide, we concluded that the solvent extraction process involved was substantially equivalent to precipitation and employed a purpose, function, and result test.

In Union Carbide Corp. v. Commissioner, supra at 240-242, we first compared the solvent extraction process with the process of precipitation in order to determine their similarities and dissimilarities. We rejected respondent’s argument that for the taxpayer’s solvent extraction process to be considered substantially equivalent to the specified process of precipitation, its solvent extraction process must be physically, mechanically, and chemically substantially similar to precipitation, and its use of the process must be found to produce a substantially equivalent enhancement or beneficiation of the ore or mineral as that produced by the commercial application of the specifically named precipitation process to a similar ore or mineral. We also did not accept the three following specific assertions respondent made in contending that the taxpayer’s solvent extraction process was dissimilar to precipitation: (1) That unlike precipitation, solvent extraction acts upon a liquid and produces a liquid; (2) that unlike precipitation as commercially applied, solvent extraction involves the use of organic compounds and organic chemical reactions; and (3) that, in the case of tungsten and vanadium, the products produced using solvent extraction are not substantially equivalent to the products of processing that does not involve solvent extraction. In resolving these points and concluding that solvent extraction was substantially equivalent to precipitation, we stated as follows:

[The taxpayer’s] comparison of the two processes in terms of similarities is more to the point: “Both processes are chemical processes involving the use of chemicals. Both processes involve the introduction of reagents. Both processes are applied to a liquid solution rather than an ore. * * * Both processes serve a concentrating function.”
******
As far as respondent’s general proposition is concerned, we think it runs contrary to the thrust of Barton Mines Corp. v. Commissioner, supra. Granted that the Second Circuit Court of Appeals did not deal directly with the issue of substantial equivalence, it did adopt an overall view of purpose, function, and result in determining the scope of the word “concentration” (a specified mining process under section 613(c)(4)(D)) (see 446 F.2d at 989), an approach also adopted by this Court (see 53 T.C. at 254, 258). Respondent’s general position would produce a significantly stricter standard for decision.
With respect to the specifics of respondent’s general assertion, we find them equally unpersuasive. The fact that solvent extraction acts upon liquid to produce a liquid seems to us a distinction without a difference in the application of the purpose, function, and results test. Similarly, we are unimpressed by the argument that solvent extraction is chemically different from any of the named processes since they all involve inorganic chemistry, and solvent extraction is an organic process. * * *
Finally, we are not persuaded that the nature and quality of the end product of the solvent extraction process are such as to preclude a holding that such process is substantially equivalent to precipitation. We recognize that the end product of solvent extraction was a more desirable commercial product than would have resulted from multiple precipitations (which respondent acknowledges * * * [the taxpayer] could have used), but that fact is not in and of itself sufficient to exclude the application of the test of substantial equivalence.
[Union Carbide Corp. v. Commissioner, 75 T.C. at 240-242; fn. refs, and citations omitted.]

In Louisiana Land & Explor. Co. v. Commissioner, 90 T.C. 630, 649 (1988), we held that income from sulphur removed from hydrogen sulfide obtained from oil and gas wells was subject to an allowance for percentage depletion under section 613(b)(1), rather that section 613A. We concluded that Congress, when it revised section 613 and enacted section 613A, did not intend to limit percentage depletion for sul-phur or any other minerals (except oil and gas) produced from an oil and gas well. We held that the limitations of section 613(d) and section 613A apply only to oil and gas, not to other minerals produced from oil and gas wells.

At trial, we ruled that in the instant case our above holding in Louisiana Land & Explor. Co. v. Commissioner, supra, collaterally estopped respondent from rearguing the issue of whether section 613 or section 613A controls the depletion of sulphur produced from petitioner’s working interests in various oil and gas wells. The parties are in dispute over whether the processing of hydrogen sulfide that took place in the Jay field and bec field sulphur recovery plants qualifies as a mining process. Petitioner contends that such processing is a mining process. Specifically, petitioner asserts that the extraction of sulphur from hydrogen sulfide using the Claus method is substantially equivalent to the specified mining process of precipitation. Respondent, on the other hand, argues that mining was completed with the separation of the hydrogen sulfide from the oil and gas and that petitioner’s extraction of sulphur from hydrogen sulfide constitutes a nonmining process under section 613(c)(5). Respondent asserts that the Claus method is not substantially equivalent to precipitation, because precipitation involves the extraction of a solid from a liquid.

Based on the purpose, function, and result test enunciated in Union Carbide, we conclude that the Claus reactor processes and subsequent condensing processes employed by petitioner are a combination of processes substantially equivalent to precipitation. As in Union Carbide, we perceive the fact that the combined Claus reactor/condensing processes extract a liquid from a gas; i.e., liquid sulphur from hydrogen sulfide, to be a distinction without a difference.

The purpose and function of the combined Claus reactor/ condensing processes are to concentrate the sulphur contained in hydrogen sulfide. This is accomplished by: (1) In the Claus reactor process, introducing a chemical reagent, sulphur dioxide, which reacts with the hydrogen sulfide, to produce sulphur vapor, and (2) in the subsequent condensing process, cooling such sulphur vapor to below its dew point and collecting the liquid sulphur that forms. As in Union Carbide, we also reject respondent’s contention that the processes fall within the “treatment effecting a chemical change” category of section 613(c)(5). Our holding that the combined processes are substantially equivalent to precipitation precludes the applicability of section 613(c)(5). Section 613(c)(5) contains a clause which expressly makes it inapplicable to those processes which qualify under section 613(c)(4)(D). Indeed, certain of the specified mining processes in section 613(c)(4)(D), including precipitation, involve chemical change. Union Carbide Corp. v. Commissioner, supra at 246.

We further reject respondent’s contention that the degree of beneficiation accomplished in extracting the sulphur is so high that the combined Claus reactor/condensing processes should be deemed “refining” under section 613(c)(5). The record reflects that additional processing would be required to attain a “high degree of purity”. See Union Carbide Corp. v. Commissioner, supra at 245; cf. sec. 1.613 — 4(g)(6)(iii), Income Tax Regs.

Petitioner offered testimony from two expert witnesses, Adrian C. Dorenfeld and Arthur R. Laengrich. Mr. Dorenfeld is a mining engineer with broad experience in the mining and metallurgical industries. Mr. Laengrich is a chemical engineer with extensive experience in designing sulphur recovery facilities.

These two expert witnesses testified that the sulphur produced at petitioner’s sulphur recovery plants is not of a high degree of purity. Mr. Laengrich testified that the sulphur produced has the same degree of purity as sulphur produced by the Frasch method. He stated that because sulphur produced under either method has the same level of purity, they are sold in direct competition with one another in the marketplace. Mr. Dorenfeld elaborated that further refining of the sulphur would be needed to produce pharmaceutical-grade sulphur.

With respect to the heating processes at petitioner’s sul-phur recovery plants, Mr. Laengrich was of the opinion that the heating processes were helpful to the Claus reactor process and had an insubstantial cost. He noted that the heaters in each plant represented only between 2 and 3 percent of such plant’s total cost. He testified that the heating processes at petitioner’s plants were employed to assure that the gas entering the Claus reactor was at a temperature above the dew point for sulphur. He explained that if the gas’ temperature were not kept above dew point, sulphur vapor formed during the Claus reaction would condense into liquid sulphur before it could be removed from the Claus reactor. If this occurred, he stated, processing of hydrogen sulfide gas in the Claus reactor would have to stop so that the catalyst’s surface could be cleaned. He acknowledged that the heating process is not necessary to the Claus reactor process, as at other sulphur recovery plants the reaction in the Claus reactor will take place at temperatures below dew point. However, by heating the gas processed to above dew point, the processing done at petitioner’s plants could proceed on a continuous basis without the periodic stops that would otherwise be needed to clean the catalyst’s surface.

Respondent offered no evidence controverting Mr. Laengrich’s testimony. We conclude the heating processes were incidental to the subsequent Claus reactor process. See sec. 1.613 — 3(f)(2)(iii), Income Tax Regs.

As to the initial cooling or condensing process that precedes the heating and Claus reactor processes, we conclude that such process was necessary to the subsequent mining processes. Union Carbide Corp. v. Commissioner, 75 T.C. at 242-244. It was necessary to cool the gas entering the Claus reactor process so as not to destroy the catalyst that facilitates the occurrence of the Claus reaction. Mr. Laengrich testified that if the initial cooling or condensing process were eliminated, the gas entering the Claus reactor process directly from the reaction furnace process would have such a high temperature that it would destroy the catalyst and prevent the Claus reactor process from operating. The Claus reactor processes at the BEC plants correspond to the Claus reactor processes at the Jay field plants. Both employ the identical catalyst.

We further conclude that the reaction furnace process employed in the sulphur recovery plants was necessary to the subsequent mining processes. Union Carbide Corp. v. Commissioner, 75 T.C. at 242-244. The reaction furnace produced the sulphur dioxide that was essential for the Claus reactor/condensing processes. Absent the reaction furnace process, the subsequent Claus reactor/condensing processes could not take place. Although high temperature is employed in the reaction furnace process, as such process is necessary to the subsequent Claus mining processes, section 613(c)(5) is inapplicable. Union Carbide Corp. v. Commissioner, 75 T.C. at 246; sec. 1.613-4(f)(2)(iii), Income Tax Regs.

In conclusion, we hold that all of the processes employed by petitioner for extraction of sulphur at the Jay field and BEC field plants qualify as mining under section 613(c)(4)(D). Petitioner’s income from sales of such sulphur is gross income from mining.

Petitioner’s Taxable Income From the Property

Under section 613(a), petitioner’s percentage depletion deduction for sulphur cannot exceed 50 percent of the taxable income from the property (computed without allowance for depletion). For purposes of section 613(a), the term “property” is defined in section 614 and the regulations thereunder. Sec. 614(a); secs. 1.611-l(d), 1.613-1, Income Tax Regs.

Section 614(a) provides the general rule that for purposes of computing the depletion allowance in the case of mines, wells, and other natural deposits, the term “property” means each separate interest owned by the taxpayer in each mineral deposit in each separate tract of land. However, under section 614(b)(3), a special rule is provided in the case of oil and gas wells subject to unitization agreements. Where one or more of a taxpayer’s operating mineral interests participates under a voluntary or compulsory unitization plan, in a single cooperative or unit plan, for the period of such participation they generally shall be treated as one property for all purposes of subtitle A of the Internal Revenue Code. Sec. 614(b)(3)(A); sec. 1.614-8(b)(l), Income Tax Regs. Such special rule will apply with respect to a voluntary unitization agreement only if all operating mineral interests covered under the agreement are in the same deposit or two or more deposits, the joint development or production of which is logical from the standpoint of conservation, convenience, economy, and geology, and which are in tracts of land that are contiguous or in close proximity. Sec. 614(b)(3)(B); sec. 1.614-8(b)(2), Income Tax Regs.

For purposes of section 614 and the regulations thereunder, the term “interest” means an economic interest in a mineral deposit and includes operating or working interests. Sec. 1.614-l(a)(2), Income Tax Regs. The term “mineral deposit” refers to minerals in place. Sec. 1.611-l(d)(4), Income Tax Regs. The term “minerals” includes ores of the metals, coal, gas, oil, and all other natural metallic and nonmetallic deposits. Sec. 1.611-l(d)(5), Income Tax Regs.

Where two or more minerals are produced from a property, regardless of whether the minerals are entitled to different rates of percentage depletion and notwithstanding that some of the minerals may be entitled to cost depletion only, a taxpayer’s taxable income from the property is such taxpayer’s total taxable income resulting from sale of all minerals produced from the property. Sec. 1.613-2(c)(2), Income Tax Regs.

Petitioner contends that in determining the taxable income from each of the various “properties”, all income from sales of oil, gas, and sulphur is included. Petitioner maintains that under the applicable regulations minerals produced from a single property simply cannot be treated as being from more than one property. Petitioner concedes that under section 613(a), no percentage depletion deduction is allowable for 1984 with respect to the Scott Paper 30-1 property, as that property had no taxable income for 1984.

Respondent, on the other hand, argues that, in computing petitioner’s taxable income from a property, only income from sales of sulphur is included. Respondent’s argument is as follows:

Section 614 defines the term “property” for the purpose of computing the depletion allowance (whether cost depletion or percentage depletion) and provides, in sections 614(b), 614(c), and 614(e), three sets of special rules for determining the appropriate unit of property in the cases of (1) operating interests in oil and gas wells or geothermal deposits, (2) operating interests in mines, and (3) nonoperating mineral interests. These three sets of special rules provide the circumstances under which mineral properties are or may be aggregated into a single unit or smaller group of units as well as the circumstances under which a single mineral property may be treated as two or more separate properties. Extensive guidance regarding the proper application of these rules is provided in Treasury Regulations under section 614.
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Because of the differing sets of rules regarding aggregations and separations of properties, depending on the type of mineral, the number of oil and gas properties that a taxpayer owns may differ from the number of nonoil and gas properties that a taxpayer owns.
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In Louisiana Land & Exploration v. Commissioner, 90 T.C. 630 (1988), this court held that the petitioners were entitled to a separate percentage depletion deduction pursuant to section 613(b)(1)(A) for elemental sulphur that was converted from hydrogen sulfide obtained from a stream of natural gas produced from an oil and gas well. This court further concluded that hydrocarbon fuels are subject to percentage depletion under section 613A of the Code and that section 613A does not affect the computation of depletion for minerals other than hydrocarbon fuels. In order to give effect to this court’s decision in a manner consistent with both the rules for determining the “property” unit under section 614 of the Code and the computational rules for determining the 50 percent of taxable income limitations under section 613(a) of the Code and regulations thereunder, the petitioner must apportion income and expenses between petitioner’s oil and gas properties and petitioner’s sulphur properties. Simply put, the petitioner owns oil and gas properties to the extent that petitioner sells oil and gas and the petitioner owns sulphur properties to the extent that petitioner sells sulphur.

We agree with petitioner. In determining the 50-percent of taxable income limitation under section 613(a), no basis exists for treating mineral interests that are to be treated, pursuant to section 614 and the regulations thereunder, as a single property for “all” purposes of subtitle A of the Internal Revenue Code, as more than one property. Petitioner owned working interests in various oil and gas wells located in the Jay and BEC fields. Oil, gas, and sulphur were produced from these wells and sold by petitioner. With respect to the Jay field, the entire field is unitized under forced unitization orders by the States of Alabama and Florida. Petitioner, therefore, is treated as having an interest in a single property. Similarly, with respect to the BEC field, under voluntary unitization agreements, there are eight producing well units, and each of those properties is treated as a single property in which petitioner has an interest. Sec. 614(b)(3)(A); sec. 1.614-8(b)(l), Income Tax Regs. We find that, for purposes of the 50-percent of taxable income limitation of section 613(a), petitioner’s’ taxable income from each property includes income from sales of all minerals produced and is not limited only to income from sales of sulphur. Sec. 1.613-2(c)(2), Income Tax Regs.

To reflect the foregoing and the agreements of the parties,

Decision will be entered under Rule 155.

APPENDIX B

APPENDIX C  