4.41.1  Oil and Gas Handbook (Cont. 1)

4.41.1.2 
Acquisitions

4.41.1.2.4 
Intangible Drilling and Development Cost (IDC)

4.41.1.2.4.9 
Offshore Development (Marine Offshore Exploration)

4.41.1.2.4.9.1  (12-03-2013)
Offshore Platforms

  1. Offshore platforms have been used for over 65 years since the first specifically designed structure was installed in the Gulf of Mexico in 1947 in a water depth of 20 feet. The industry is now capable of installing platforms in water depths of several thousand feet. Two of the largest combination drilling and production platforms in the world are located in the Gulf of Mexico. The improved techniques of fabrication and erection developed for use on Gulf of Mexico structures have influenced construction worldwide.

  2. It is not economical to use fixed-jacket platforms to produce oil and gas from water depths greater than 800 feet. Instead, deepwater platforms are typically floating and employ either a semi-submersible or "spar" design that requires mooring lines to hold it in place.

4.41.1.2.4.9.2  (12-03-2013)
Offshore Drilling Rigs and Mobile Offshore Drilling Units

  1. Offshore drilling rigs that are installed on platforms are generally similar to drilling rigs used on land. In many circumstances it is more practical to drill wells from a "Mobile Offshore Drilling Unit" (MODU). Certain MODUs can drill and complete wells in water depths approaching 10,000 feet. The principal types of MODUs are:

    1. Semi-submersible. This MODU is an integrated unit of large dimensions consisting of tubular hulls or pontoons on which are mounted cylindrical columns supporting a fixed upper deck which serves as the drilling platform for the drilling rig. In deep water, the unit is operated from a floating but "semi-submerged" position in which the lower hull assembly is about 40 feet below the water surface. The unit is held in the drilling position by a number of large anchors and heavy chains. In shallow water, the unit can operate as a "semi-submersible" with the lower hull sitting on the bottom. It is not self-propelled and must, therefore, be towed to the drilling location.

    2. Jack-up drilling rig. This MODU has legs which are carried generally above the water when the unit is towed. When in use, the legs are lowered until they reach the bottom and penetrate the ocean floor, thereby permitting the hull to be lifted up by the legs until it becomes stationary above the surface of the water. The hull then serves as a drilling platform. This unit is not self-propelled.

    3. Self-propelled marine drilling rig. Sometimes called a "drillship" , this drilling rig is self-propelled. It has crew living quarters which are located on deck behind the drill. Below deck space is entirely taken up with drilling equipment, anchors, and other types of machinery. Modern drillships are held in location by thrusters instead of mooring lines.

4.41.1.2.4.9.3  (12-03-2013)
Platform Construction Costs

  1. In general, construction of platforms involves three stages:

    1. Design Phase. During this phase engineers design specifications peculiar to each platform and its planned location.

    2. Land Phase. Prefabrication of as much of the platform as possible occurs on land.

    3. Marine Phase. The platform in its component form is towed by a barge to the drill site, where it is assembled and erected in place.

  2. The marine phase requires specialized construction equipment such as a combination derrick and pipe laying construction barge. These are constructed in two types. The semi-submersible drilling barge, on which is mounted a heavy lift crane instead of a drilling rig, is used in constructing offshore platforms and other production facilities. The barge also contains equipment necessary for the laying of large diameter pipelines on the ocean floor. The second type of surface floating barge performs the same functions as a semi-submersible barge but is constructed with a flat bottom and works in a floating, rather than a submerged, position. This unit is likewise not self-propelled.

  3. The examination of IDC may reveal that costs applicable to platform construction and erection have been included in IDC. The agent should obtain the services of an engineer for assistance in the examination of proper treatment to be awarded platform construction costs.

  4. An offshore platform may structurally support a drilling rig that is used to drill some or all of the wells that produce to the platform. If the production equipment is located on an adjacent platform, the platform supporting the rig is called a drilling platform. The intangible costs associated with a drilling platform can be deducted as IDC. If the platform supports the rig and contains the production equipment it is called a "dual purpose" platform. The cost of dual purpose platforms is discussed in Rev. Rul. 89-56, 1989-1 CB 83.

  5. Platforms that do not structurally support a drill rig during the drilling phase of an offshore development are referred to as production-only platforms, or simply production platforms. Generally the cost of a production platform should be recovered via depreciation.

4.41.1.2.4.9.4  (12-03-2013)
Platform Costs Litigation

  1. In Exxon Corp. v. U.S., 547 F.2d 548, 39 AFTR 2d 442 (Ct.CI. 1976) the court considered costs incurred in the fabrication of "templet type" platforms. The court held that the cost for labor, fuel, repairs, supplies, and hauling incurred in fabricating the standardized components were eligible for IDC option to expense.

  2. In 1981, the tax court considered similar issues in Standard Oil Co. v. Commissioner, 77 TC 349 (1981) with respect to jacket type platforms, and in Texaco Inc. v. United States, 598 F.Supp. 1165 (S.D. Texas 1984) and Gulf Oil Corp. v. Commissioner, 87 TC 324 (1986), 54 AFTR 2d 6308 (SD Tex 1984) the courts considered several different types of offshore platforms which were designed and constructed for use at specific platform locations. And the court held that the platform or components were not items "ordinarily" considered salvageable.

  3. In view of these decisions, the Service decided it would no longer follow Rev. Rul. 70–596, 1970-2 CB 68 which held that all expenditures incurred in the onshore fabrication of offshore drilling and production platforms are ineligible for IDC expense. Rev. Rul. 89–56, 1989–1 CB 83 held that the deductibility of expenditures related to the onshore fabrication of offshore drilling and production platforms as IDC would be determined on a platform-by-platform basis depending on whether the platform is customized for a specific drill site or salvageable.

  4. In LL&E v. Commissioner, 102 T.C. 21 (1994), the IRS argued that production equipment located on a dual purpose platform that was used in drilling operations for a short period of time was ineligible for IDC expense under a "primary purpose" test. The Tax Court determined that the primary purpose test did not exist and that all equipment used in drilling is generally eligible for IDC expense. The IRS acquiesced in the court's decision. See AOD, IRPO 51,058, Louisiana Land and Exploration Co. v. Commissioner, Basis for Cost Depletion, File No. AOD/CC-1995-008 (August 7, 1995).

4.41.1.2.4.9.5  (12-03-2013)
Each Platform Analyzed Separately

  1. Design and fabrication expenditures may be treated as IDC if the evidence shows the following:

    1. The platform in question is incident to and necessary for the drilling of wells even though it is subsequently used for production.

    2. The platform is designed and constructed for use at a specific site.

    3. And platforms of that type are not ordinarily used or otherwise salvaged as a unit.

  2. When a platform is determined to be eligible for IDC treatment, an analysis of the salvageability of its structural components and subcomponents may be required. For example, the onshore fabrication cost of a standardized and reusable compressor package is not subject to IDC treatment simply because it will be installed on a platform and used in drilling operations but if the package is further integrated into a larger unsalvageable component or the platform itself, both the original fabrication costs and the additional costs involved in the integration will likely qualify for IDC treatment.

  3. The most significant references applicable to costs of acquiring, transporting, and erecting offshore platforms in connection with oil and gas properties can be found in IRC 263(a) and (c), Treas. Reg. 1.612–4; Rev. Rul. 89–56, the decision in Exxon Corporation v. United States; Louisiana Land and Exploration Co. v. Commissioner , 102 TC 21 (AOD, IRPO 51,058, Louisiana Land and Exploration Co. v. Commissioner, Basis for Cost Depletion, File No: AOD/CC-1995-008,(August 7, 1995); GCM 37359; and GCM 39085.

  4. The issue of which particular costs incurred to construct and install offshore platforms are IDC has been ongoing since the 1970's. The examination of IDC may reveal that costs applicable to platform construction and erection have been included in IDC. Examiners should request engineer assistance in the examination of proper treatment to be awarded platform constructions costs. The Action on Decision in Louisiana Land and Exploration Co. v. Commissioner should be reviewed by the engineer.

  5. With respect to platform dismantlement or well plugging, examiners should also review IRM 4.41.1.3.2.9.

4.41.1.2.4.9.6  (12-03-2013)
"Subsea Wells" and Deepwater Platforms

  1. Significant advances related to Mobil Offshore Drilling Units (MODUs), floating offshore platforms, and "subsea" wells and related infrastructure have permitted the economical production of oil and gas from deepwater locations in the 21st century, especially in the Gulf of Mexico. Modern MODUs can drill and complete wells in water depths approaching 10,000 feet. These wells are extremely expensive to drill and (if successful) to complete. Because intervention in these wells is also very expensive, the operator conducts extensive tests of the mechanical systems of the well before the MODU is released.

  2. A key characteristic of a subsea well is that its wellhead (aka "christmas tree" ) is located on the seabed (a "wet tree" ) instead of being located on an offshore platform (a "dry tree" ).

  3. Subsea flow lines carry production from the subsea well to processing equipment located on a platform. Subsea control cables, which are known as "umbilical lines" , connect the subsea well to a control center located on the platform. The distance between wells and the platform may be 20 miles or more. Technological advances have made it feasible in certain situations to install equipment near the subsea wells such as separators, booster pumps and water injection pumps. Remotely operated underwater vehicles (ROVs) are used to carry out the work of connecting the wet trees, lines, and equipment packages.

4.41.1.2.4.9.7  (12-03-2013)
Issues with Subsea Wells and Deepwater Platforms

  1. The costs of subsea wells and deepwater platforms are usually examined by IRS engineers. One issue involving the long-term use of a MODU illustrates the complexity:

    Example:

    An oil company makes a large payment to a drilling contractor to modify a MODU so that it can carry out certain tasks when drilling wells for the oil company. The oil company contracts to use the modified MODU for a number of years under typical commercial terms. The oil company improperly deducts the payment for modifications as IDC. The payment should be amortized over the life of the contract to use the modified MODU because the contract is an intangible asset. If the oil company acquired equipment to be used for drilling it would recover the cost via depreciation.

  2. Examination issues involving IDC deductions are summarized as:

    1. Intangible costs, such as those incurred for design, fabrication, and installation of subsea flowlines and umbilicals are often deducted as IDC by taxpayers. Their basic premise is that initial production of a subsea well from the seafloor to the processing equipment located on a platform is analogous to the "flow tests" which were conducted by the operator in the Louisiana Land and Exploration Co. v. Commissioner case cited in IRM 4.41.1.2.4.9.5. The intangible cost of production equipment used in those flow tests was found to be deductible as IDC. To understand how subsea assets are generally distinguishable from the equipment described in the LL&E case, and not treated as IDC, it is useful to review why the court reached its conclusion.

    2. In Louisiana Land and Exploration Co. v. Commissioner, the flow tests were conducted as part of the completion operation for each well. The wells had been perforated in stages and after each stage was added, the well was flowed (produced) for several hours to determine if the desired production rate was achieved. Only then did the operator shift drilling and completion work to another well. Permanent production equipment had been used to conduct the flow tests. The court determined the subject equipment was incident to and necessary for the development of wells, and therefore was allowable as IDC. The IRS acquiesced and no longer argues that the primary use of equipment in production operations negates the fact that it was used in the development of wells.

    3. IRS engineers have not found a situation where the subsea flowlines, umbilicals and production equipment were utilized in the same manner as the equipment in the Louisiana Land and Exploration Co. v. Commissioner case. Rather, the productive capability of modern deepwater wells is normally verified by analyzing data from seismic surveys, numerous well logs, pressure measurements and rock and fluid samples retrieved by sophisticated sampling tools lowered into the well from the MODU. In circumstances where additional confirmation is needed, the operator will produce the well to portable flow test equipment located on the MODU. The well may be temporarily abandoned at this point to allow analysis of the data and design of completion assembly. Regardless, a MODU will be utilized to perform all of the final completion operations, including installation of the subsea tree before leaving the location.

    4. Typically, operators will assign responsibility of a subsea well to a specific internal group depending on the status of the well. Examples of such groups include the drilling and completion team, the flowline and umbilical installation and hookup team, the well and facilities start-up team, and finally the production operations team. The transfer between groups is usually accompanied by certain documents (generally known as pre-commissioning reports, commissioning reports, or "hand-off packages" ). Inspections of those documents have shown that the wells are generally viewed by the operator as being "completed" and "ready to produce" prior to initial production to the platform.

    5. A review of operators' press releases and official SEC filings show that prior to initial production of subsea wells it is not uncommon for the wells to be referred to as "successful" , for operators to have expended very considerable sums to construct an offshore platform, and for significant quantities of proved reserves to be recorded. The latter is especially significant since reservoirs are only considered proved when production of oil and gas in economic quantities using existing operating methods is known or reasonably certain.

    6. In summary, intangible costs surrounding subsea flowlines, umbilicals, production equipment, and production platforms are not deductible as IDC. The entire cost should be recovered by depreciation starting in the year they are placed in service. When conducting a risk analysis, examiners should take into account the effect of bonus depreciation and be mindful that the issue surrounding these costs and placement of assets often span multiple years.

4.41.1.3  (10-01-2005)
Production and Operation of Oil and Gas Properties

  1. This section provides guidelines on the production and operation of Oil and Gas Properties.

  2. Oil and gas production is the ultimate objective of acquiring rights to an oil and gas property. The drilling and completion of a well is necessary before an oil and/or gas property enters its production stage.

  3. "Production and Operation" means the day-to-day activities necessary for the production and sale of crude oil and/or natural gas. Oil is produced from the wells either by natural pressure in the reservoir or by "artificial lift." "Artificial lift" usually consists of installing a regular plunger and sucker rod-type pump in the well. However, it can also be accomplished by use of "gas lift" or by hydraulic pump. The operation of an oil and/or gas lease involves the use of lease and well equipment. The operation requires expenditures for and the use of utilities, power, labor and supplies. Except for the integrated producer, the oil and/or gas produced is usually sold to a larger integrated operator who transports it to his/her facilities by pipeline. Oil sometimes is sold to a trucking company which resells it to a refiner.

  4. The accounting and income tax implications involving oil and gas are often complicated by the fact that drilling and completion activities are continuing on the same property that contains production operations.

  5. An understanding of the typical operation will aid in the discussion of the auditing techniques dealing with each type of interest owner.

  6. Basically, there are two types of interests in oil and gas properties: operating and nonoperating. The most common types of interests are also described as working interests and royalty interests. See Exhibit 4.41.1-2. The distinct difference is that the working interests bear all the operating costs of the property. The royalty interests are free of all operating costs except taxes. There may be several royalty interest owners and working interest owners in a single oil and gas property.

  7. The owners of the working interest in an oil and gas property will designate one of the working interest owners as the "operator;" or they may designate someone who does not own an interest in the property as the operator. The operator is responsible for the physical operation of the oil and gas wells.

  8. Typically, the operator will own an interest in the property, but it is not necessary. The operator is usually someone experienced in the operation of oil and gas properties. The operator performs the necessary functions to produce the oil and gas and bills the working interest owners for their proportionate share of the expense, which includes overhead and a profit factor for the operator. Royalty owners do not pay any expense except for production taxes and ad valorem taxes. However, some states allow an operator to bill the royalty owner for its share of certain "post production" costs such as the cost to compress the gas so that it can be sold to a pipeline purchaser.

  9. In some cases, the working interest owners will allow the operator to sell their share of the production, deduct their share of the expense of operation, and remit the net amount due them. Refer to IRM 4.41.1.3.2.6 Joint Billing, where, depending on the circumstances, a question may arise as to whether or not this arrangement may be an association taxable as a corporation. Otherwise, the purchaser of the production remits the owner's share directly and the operator bills the working interest owner for its share of the lease operating expenses.

  10. Regardless of the method of settlement between the operator and the working interest owners, the operator sends out information, usually in the form of a detailed statement of each item of expense, equipment and revenue, that relates to the property on a monthly basis. The owner's share will be computed on this statement. Royalty owners are usually paid directly by the purchaser of the production.

  11. The typical operation described above is very simplified. Each operator will conduct operations slightly different. Suggestions to help the examiner identify and develop areas are described in the following sections.

4.41.1.3.1  (10-01-2005)
Sale of Oil and Gas

  1. Underreporting of the proceeds from oil and gas sales is facilitated by the practice, common in the industry, of assigning the income from proven properties as collateral on loans and paying the oil runs directly to the lender. Another problem is the sale of production payments and having a percentage of the oil and gas sales proceeds paid directly to the owner of the production payment. The following sections describe various types of problems that may be encountered and suggested auditing techniques for determining the correct income to be reported from oil and gas sales. See Exhibit 4.41.1-11.

4.41.1.3.1.1  (12-03-2013)
Income to Royalty Owner

  1. Income from oil and gas royalties is passive-type income derived from the landowner's royalty, overriding royalty, or a net profits interest. This type of income bears none of the burden of operations or development except taxes and any "post production" costs that state law allows an operator to charge a royalty owner in order to make the production marketable, such as for gas compression. Royalty income may be paid by the operator of the property or by the purchaser of the crude oil or gas production. In either event, the royalty owner should receive a statement with the check (usually monthly but at least periodically) showing the total sales of oil and gas from the property, interest in the property, and the amount of production. Taxpayer will normally report royalty income on Schedule E as rents and royalties or from flow through entities. The taxpayer can have both royalty and working interest income and report both on a Schedule C.

  2. Oil and gas royalty interests in proven properties make excellent investments and collateral for loans because they require no services or decisions on the part of the owner. Banks and other lenders will gladly accept royalties as collateral for loans because their value can be easily determined, and the income can be assigned and forwarded directly to the bank or other lender from the purchaser of the production.

  3. Probably the most effective auditing technique for discovering underreporting of income from royalties and the unreported sale of a royalty interest is the comparison of both prior and subsequent years' returns with the year under examination.

  4. Secure a detailed schedule of the oil and gas properties and note any unusual increases or decreases in the income reported. Determine the reasons for all unusual increases or decreases. The depletion schedules can be used for this purpose in most instances.

  5. An often neglected tool for securing information concerning practices of the taxpayer involving the assignment of royalty interest is to question the taxpayer, chief accounting officer, or someone in a position to know if there have been assignments or sales of royalty interests.

  6. Another technique is to request the oil or gas "run tickets " from the operator, on a test basis, to compare with the income reported in the books.

  7. If the taxpayer assigned all income, deducted tax liability is available.

4.41.1.3.1.2  (10-01-2005)
Income to Working Interest Owner

  1. The term working interest may also be referred to as an operating interest. The operating or working interest is burdened with all of the costs of development, completion, and operation of the property.

  2. Some confusion may exist between an "operator" (one who physically operates the property) and a person who owns a part of the working interest but is not an operator of the property. There may be several working interest owners, but only one of them will be the "operator." All of the working interest owners bear their share of the costs of operation. The working interest owners will make all decisions concerning the operation of the property, including the selection of an operator for the property. The selected operator makes all routine operating decisions.

  3. There are a number of problems that can develop and have tax consequences to the working interest owner. In this section, situations relating principally to income will be covered.

  4. Some indicators on the return that should trigger questions concerning the proper reporting of income are:

    1. Leases that continue to operate at a loss and no drilling or development is being done

    2. Income from the property is not representative of the expense being incurred

    3. Large intangible development costs are being incurred but indications of the property being transferred before the income is realized

      Example:

      Transferred to a trust or other family member.

  5. A proven technique for identifying properties that may not be reporting the proper income is the comparison of detailed operating schedules of both the prior and subsequent years. The reasons for significant changes from year to year should be investigated.

  6. If a lease is continuing to operate at a loss or the gross revenue is not representative of the costs of operation, there is a possibility that a portion of the lease income has been assigned to a third party, or another person's expenses are being paid.

  7. To determine the proper amount of income that should be reported from any property, obtain the "run tickets." The run tickets show information identifying the lease and tank involved. A copy of the run ticket is furnished to the operator for each movement of oil from lease tanks. This test should be considered on a sample basis in many examinations. The size of the return and volume of production would influence this decision.

  8. If there is a need to verify the taxpayer's interest in the property, secure the "lease files." This should contain the lease agreement, division orders, any assignments, letter agreement, etc., pertaining to the property. These files will vary in content from case to case. It should be noted, however, that these files represent title to valuable assets, and care should be exercised in their use. Taxpayers are very protective of the lease files, and rightly so.

  9. If a taxpayer is incurring large intangible development costs on properties to get them to the production stage and then making a practice of transferring them to family members or trusts, it may be that this practice can be attacked under IRC 183 as not being engaged in business for a profit or under IRC 671 through 678 as an assignment of income.

4.41.1.3.1.3  (01-01-2005)
Gas Balancing Agreements

  1. Working interest owners will routinely execute a gas balancing agreement to deal with situations where one or more of the parties is unable to take or market its share of production from the underlying property. When imbalances occur, there will be a party that has underproduced and a party that has overproduced. Most balancing agreements dictate that imbalances will be reconciled via future gas production where possible, and cash if need be when the property ceases production.

  2. Due to a concern that taxpayers were not consistent in their method of reporting income from gas sales when imbalances occurred, the IRS issued regulations in 1994 for joint ventures that elect out of the provisions of Subchapter K of the code. See Treas.. Reg. 1.761-2(d). The regulation mandates that the cumulative gas balancing method be used for tax purposes unless the IRS provides advanced permission to use the annual gas balancing method.

  3. A key provision of the cumulative gas balancing agreement is that each producer recognizes income currently for the gas that it actually markets. An overproducer may only claim a deduction in the year in which a balancing payment is made to the underproducer. The underproducer would recognize income at that time.

  4. The depletion deduction generally follows the recognition of income. However once an overproducer has cumulatively produced more than its share of gas in the reservoir (tip-over), it may not claim depletion on gas that it has taken from underproducers.

4.41.1.3.1.4  (10-01-2005)
Assignment of Income

  1. A practice unique in the oil and gas industry is the assignment of income from a property to a third party. This may be done for a variety of reasons and may cover a period of time until a specific amount of income is realized. The assignment of income from the property to be paid over a period shorter than the economic life of the property (a noncontinuing interest) constitutes a production payment provided that it meets the definition found in Treas. Reg. 1.636–3(a).

  2. The Tax Reform Act of 1969 made major changes in the tax treatment of production payments. Effective with respect to production payments created after August 7,1969, they are to be treated as loans (Treas. Reg. 1.636–1). The only exception is a production payment carved out of a mineral property and pledged for the exploration or development of such property (see Treas. Reg. 1.636–1(b)). Refer to IRM 4.41.1.3.1.6 and IRM 4.41.1.4.3 for a discussion of production payments.

  3. Since the revenue relating to the production payment may be forwarded directly from the first purchaser of the production to the owner of the production payment, it is difficult to discover the existence of one without special tests being conducted. It a production payment exists, and the property is sold during the year, the sale is encumbered by the existence of the payment, similar to the assumption of a mortgage.

  4. There are several things that can be done that will aid in the discovery of the existence of a production payment. If possible and practical, the taxpayer or other responsible official who would know of the existence of a production payment should be questioned. Compare prior and subsequent years detailed schedules of income from oil and gas with the year under examination, and secure an explanation of all material increases and decreases in income reported. Inspect the lease files on a selected basis, especially for those properties that have been sold during the year under examination. The contract for the sale of the property should also be inspected to ascertain the existence of an outstanding production payment or the retention of one. The Securities and Exchange Commission's (SEC) Form 10–K may describe production payments if they are material.

4.41.1.3.1.5  (07-31-2002)
Operator Service Income

  1. Operators of oil and gas properties are those persons or organizations that physically operate the equipment on the leases that produce the oil and gas income. For this service, operators charge the working interest owners a fee or service charge. Usually this charge is based on the number of wells involved. The charge may be based on the actual expense of operating the lease by the operator, plus overhead and profit factor. The operator may have an interest in the property, but it is not a requirement.

  2. Operators are usually experienced in operating oil and gas leases. They often have considerable production of their own in addition to the service income from operation of the oil and gas properties for the account of others. The size and volume of an operator's business will vary from a small proprietorship to a major oil company.

  3. A unique auditing problem associated with operators develops when they own a part of the working interest in those properties where they are also the operator. Some operators have been known to report the reimbursement from other working interest owners as income from the property and to claim depletion on it. Another abuse resulting from improper accounting is the crediting of lease operating expense accounts with the overhead charges to other working interest owners. This practice sometimes results in increased net income from the property (because the operator "makes a profit" for operating the property of others) and perhaps additional percentage depletion if the net income limitation otherwise would be applicable. This should not be allowed. Examiners should consider whether an adjustment would be material. Operator service income should generally be handled as a separate and distinct business, not a part of an oil and gas lease operation.

4.41.1.3.1.6  (12-03-2013)
Production Payments Pledged for Development

  1. The general rule is that a production payment carved out of a mineral interest and sold, or retained on the sale of a mineral interest, is treated in the same manner as a loan on the mineral properties (Treas. Reg. 1.636–1).

  2. The only exception to the general rule is a production payment carved out of a mineral property that is pledged for exploration or development of such property (Treas. Reg. 1.636–1). The Regulations are very specific that certain conditions must be met before the production payment will qualify for treatment under this exception.

  3. A production payment shall not be treated as carved out for exploration or development to the extent that the consideration for the production payment:

    1. Is not pledged for use in the future exploration or development of the property or properties which are burdened by the production payment

    2. May be used for the exploration or development of any other property, or for any other purpose than that described in (a) above

    3. Does not consist of a binding obligation of the payee of the production payment to provide services, materials, supplies, or equipment for the exploration or development described in (a) above

    4. Does not consist of a binding obligation of the payee of the production payment to pay expenses of the exploration or development described in (a) above

  4. Whether a production payment meets the criteria of being "pledged for development" is a question of fact to be determined in light of all relevant information that should be considered. Three factors should be verified in each case of a production payment allegedly pledged for development:

    1. The development must relate to the property burdened by the production payment.

    2. The proceeds must be used for exploration and development, not for the production of minerals. The Regulations indicate that one of the tests that should be applied is whether or not there has been any prior production from the mineral deposit burdened by the production payment. If there has been production, it may not meet the exception of Treas. Reg. 1.636–1(b) as production payment pledged for development.

    3. Repayment of the production payment must be only from the property involved and not from other leases or by a guaranty letter. See Brountas v. Commissioner, 73 T.C. No. 42 (1979).

  5. To be classified as a production payment, there must be sufficient anticipated reserves to "pay off" the production payment.

    Example:

    On wildcat (untested) leases, reserves (if any) are not known. Any future wells drilled may be dry holes. Treas. Reg. 1.636–3(a) states that a production payment "right to a mineral in place has an economic life of shorter duration than the economic life of a mineral property burdened thereby."

  6. Therefore, in the case of a dry hole property or if a taxpayer cannot establish reserves which will extend beyond the life of the payment, the owner of the production payment could have an economic interest in the property during its entire productive (if any) life. In that case, the payment must be classified as a royalty interest, not a production payment and is treated as a capital sale and a capital purchase.

4.41.1.3.2  (10-01-2005)
Operating Expense

  1. There are three phases of activity referred to in the oil and gas industry involved in attaining production of minerals:

    • Acquisition of the mineral property

    • Exploration and development

    • Operation

  2. Each of these three phases requires the expenditure of funds, and different tax treatment is accorded each.

    Example:

    Acquisition costs of a mineral property must be capitalized. However, the taxpayer may elect to capitalize or expense IDC incurred during the exploration and development phases. Operating expenses are taken into account in accordance with the taxpayer's method of accounting. It is important, therefore, to be able to distinguish or categorize the various expenditures that will be encountered in an oil and gas producer's return.

  3. Operating expenses of an oil and gas lease will include both direct and indirect expenses and depreciation. It is essential that expenses be segregated by property in order that the taxable income of each one can be determined if the income from the property is subject to percentage depletion.

4.41.1.3.2.1  (07-31-2002)
Definition of "Operating" Expense

  1. "Operating" expense is commonly referred to as "Lease Operating Expense." It includes the cost of operating and maintaining producing oil and gas leases. It includes labor for operating, maintaining the equipment on the lease, repairs and supplies, utilities, automobile and truck expenses, taxes, insurance, and overhead expenses such as bookkeeping, billing costs, and correspondence.

4.41.1.3.2.2  (10-01-2005)
Operating Expense vs. Intangible Development Costs (IDC) vs. Capital

  1. Even though the majority of taxpayers elect to currently deduct IDC, it is still necessary to be able to distinguish between operating expense, IDC, and capital expenditures.

  2. The most comprehensive definition found in the Regulations, rulings, and court decisions relate to IDC. Treas. Regulation 1.612–4 describes the usual expenditures that should be classified as IDC. IDC are those expenditures involved in the drilling and preparing of wells for production which in themselves do not have a salvage value.

  3. Expenditures that must be capitalized involve both the acquisition of the leasehold and equipping the property for production. The usual costs associated with the acquisition of an oil lease that are required to be capitalized are:

    1. The bonus paid to the landowner

    2. Commissions paid if acquired through a broker

    3. Abstracting costs

    4. Attorney fees for title opinion and for drafting instruments of agreement or conveyance

    5. Landman or land department expenses

    6. Transfer fees and taxes. If geological and geophysical expenditures are instrumental in the lease being acquired or retained, they are also required to be capitalized. However, see IRC 167 regarding amortization of geological and geophysical expenditures for tax years beginning after the enactment of the Energy Tax Incentives Act of 2005.

  4. Expenditures required to be capitalized in equipping the lease for production include the cost and installation of flow lines, pipelines, separators, tanks, roads constructed for the purpose of operating the lease, installation of electric lines, and pumping units. These are the usual types of equipment that will be required on producing properties. Different production problems, climatic conditions or environmental laws may require other types of equipment. The basic rule for the capitalization of expenditures relating to the equipping of leases for the production of oil and gas is not unlike that in any other industry.

  5. The rule relating to expenditures that will qualify as IDC (Treas. Reg. 1.612–4) has developed over the years and has been influenced by several court decisions. There are court decisions being decided today that will no doubt have a future impact on the definition of IDC. The examiner must be aware that he/she cannot follow a court decision decided against the Government unless the Commissioner announces his agreement with the decision or it is a Supreme Court decision.

  6. In the examination of a lease operating expense, expenditures will be found for servicing the well, often called workover expenses, such as pulling rods, acidizing, fracturing, cleaning out, etc., all of which are operating expenses. Closely associated with these expenditures are others that have been held to be IDC.

    Example:

    The fracturing of the producing sand with nitroglycerine before being placed in production and the cleaning out of the well.

    1. Refer to P-M-K Petroleum Co. v. Commissioner, 24 B.T.A. 360 (1931); rev'd, 66 F.2d 1009 (8th Cir. 1933); 12 AFTR 1335. The deepening of an existing well was held to be intangible development costs in Monrovia Oil Co. v. Commissioner, 28 B.T.A. 335 (1933); aff'd on another issue, 83 F.2d 417 (9th Cir. 1936); 17 AFTR 978; 36–1 USTC 521.

  7. There is no simple way of distinguishing workover costs that are proper operating costs from those that are IDC. Inspection of invoices or Authorization For Expenditures (AFE) will reveal deepening expense. This will be obvious from an inspection of the invoice. Fracturing of the producing zone in a well before it has produced oil is a fact that will have to be determined from production records or other sources of information that should be in the possession of the taxpayer.

  8. Before a lot of time is spent on this item, its significance in terms of tax impact should be considered. If the taxpayer has elected to expense IDC and there is no prospect for alternative minimum tax, there is no point in an intensive investigation to distinguish subtle IDC from operating costs.

  9. All of the costs relating to the acquisition of an oil and gas lease should be capitalized; but frequently, only the bonus is considered a capital expense by the taxpayer with the result that all of the other costs are charged to expense. In every lease acquisition there may be commissions or finder fees involved, abstracting costs, attorney's fees for title opinions and drafting deeds, and instruments of conveyance. If the property has production, there may be engineering costs involved in the appraisal of the equipment and study of the oil and gas reserves. Some companies have sufficient leasing activity to warrant employment of a "landman" , a person experienced in mineral leasing activities. The landman's salary and expenses should be a part of the capitalized lease cost if they can be identified with the acquisition of a particular mineral lease. The same would be true of a "leasing department." This has been an item of controversy in examinations of some oil producers. Their argument was that the landman and leasing department expenses could not be identified as pertaining to a single lease acquisition, and they considered and rejected many more than they acquired. There is some merit to their argument that not all of the costs of operating the leasing department should be allocated to the leases acquired. Therefore, the cost may be allocated between the successful and unsuccessful attempts of acquiring leases on some reasonable basis if an adjustment would be material.

  10. Equipment costs are usually included in billings from operators or drilling contractors along with other costs such as IDC. The billings will typically itemize all of the different costs involved such as day work, cementing, cleaning out, fuel, etc., and, if equipment is involved, a description of the equipment such as pumping units, flow lines, tanks, etc. The taxpayer's classification is usually on the face of the billing. It will be necessary to secure the invoices to verify the proper capitalization of equipment costs.

  11. Taxpayers with a large volume of oil and gas transactions will have an accounting manual that describes how the various expenditures are to be classified. This manual should be studied for accounting policies inconsistent with the Service's position.

  12. See Exhibit 4.41.1-10 for items to consider during preparation of Forms 4318, 4764, 4764-Bs, and 886As.

4.41.1.3.2.3  (07-31-2002)
Overhead Costs

  1. Treas. Reg. 1.613–5(a) defines taxable income from the property as being gross income from the property as defined in Treas. Reg. 1.613–3 and 1.613–4, less all allowable deductions (excluding any for depletion) which are attributable to mining processes including mining transportation, with respect to which depletion is claimed. These deductible items include operating expenses, administrative and financial overhead, depreciation, taxes deductible under IRC sections 162 or 164, losses sustained, and IDC.

  2. Administrative and financial overhead items include expenses of a general nature. They would include office expense, accounting, rent, administrative salaries, utilities, insurance, interest expense not assignable to a particular lease, and other financing costs.

  3. Treas. Reg. 1.613–5(a) provides that "expenditures which are attributable both to the mineral property upon which depletion is claimed and to other activities shall be properly apportioned to the mineral property and other activities. Where a taxpayer has more than one mineral property, deductions which are not directly attributable to a specific mineral property shall be properly apportioned among the several properties."

  4. Historically, the taxpayer has been allowed some latitude in this area. Businesses are constantly changing, and the percentage of overhead to be apportioned to mineral properties and other activities may vary from year to year.

  5. There are two generally accepted methods of allocating overhead cost among several mineral properties:

    1. Allocated among the several mineral properties based on the gross income from the property

    2. Allocated among the several mineral properties based on the direct expenses of each (preferred method). See Exhibit 4.41.1-9.

  6. Usually it is not to the taxpayer's advantage to distribute overhead using the same method year after year, and there is a temptation to switch from one method to another. The taxpayer should not be allowed to make this switch solely for tax advantages. This practice raises the issue of whether the allocation of indirect cost constitutes a method of accounting for which changes should not be allowed without prior consent of the Commissioner of Internal Revenue Service. See IRC 446(e). Overhead should also be allocated to drilling costs because of the impact on the minimum tax and IRC 1254, Recapture of IDC. See Occidental Petroleum v. Commissioner, 55 T.C. 115, 1970 where the court held the apportionment of such costs was not a method of accounting.

4.41.1.3.2.4  (12-03-2013)
Depreciation

  1. Treas. Reg.1.611–5 provides a reasonable allowance for depreciation of improvements made to oil and gas wells. The deduction allowed under IRC 611 is determined under IRC 167.

  2. Depreciation expense should be determined for each mineral property because it is a proper deduction for determining taxable income of the mineral property under Treas. Reg. 1.613–5(a).

  3. Treas. Reg. 1.611–5 also provides that, for purposes of IRC 167, the unit of production method may be an appropriate method. The unit of production method of accounting will be encountered frequently in the examination of tax returns of oil and gas producers.

  4. Many of the major oil and gas producers have adopted the Modified Accelerated Cost Recovery System (MACRS) available under IRC 168, which tends to eliminate disputes with the IRS over useful life and salvage value of assets. There are, however, many oil and gas producers who use the unit of production method.

  5. In the computation of depreciation under the unit of production method, using the proper oil and gas reserves and a reasonable estimate of salvage value is important. Examiners should verify that estimated salvage value is reflective of the taxpayer's experience with disposing of retired assets. Joint operating agreements between working interest owners may include an agreed-upon method to determine salvage value when assets such as pumping units are retired and the operator takes physical and legal possession of them. If a dispute arises, an IRS engineer may need to be consulted.

  6. Examiners may find that taxpayers are improperly reducing the estimated salvage value of their assets by up to 10 percent of the basis of the assets. Regulations 1.167(a)-(1) and 1.167(f)-1 suggest this is allowable, but the underlying code provision, IRC 167(f) was repealed several years ago and the regulations have not yet been revised.

  7. There is sometimes a difference of opinion between the IRS and some taxpayers regarding the proper reserves to be used for computing depreciation using the unit of production method. One court decision decided against the IRS held proven, but undrilled acreage in an oil/gas property was not to be taken into account in determining the reserves to be used in computing depreciation using the unit of production method Dulup Oil Co. v. Commissioner, 42 B.T.A. 1477; Memo 8–14–1940; rev'd and rem'd on another issue, 126 F.2d 1019 (5th Cir. 1942); 29 AFTR 60; 42–1 USTC 336.

  8. There has been no further clarification of this point either in court decisions or rulings. The consensus among IRS oil and gas engineers is that, if the taxpayer accounted for the oil or gas well equipment on each well and used the oil and gas reserves expected to be produced by that well, there would be no objection taken to this practice. In contrast the total reserves of the mineral property should be used to depreciate equipment that is common to all of the wells on the mineral property such as separators, heaters, treaters, and tank batteries.

  9. It should be relatively easy to determine if a taxpayer is using the unit of production method of depreciation. The instructions for Form 4562, Depreciation and Amortization (Including Information on Listed Property), state that depreciation which is computed by that method should be entered on Line 15 and a separate sheet with certain information attached.

4.41.1.3.2.4.1  (12-03-2013)
Placed-in-service date of wells

  1. Expenditures for the steel casing and associated downhole equipment must be capitalized. Refer to Rev. Rul. 78-13, 1978-1 CB 63. These items are placed in service and are subject to depreciation when an oil or gas zone is found, and the well completed and made capable of production. If an oil or gas zone is not found (i.e., a nonproductive well was drilled), those assets are not placed in service and are not subject to depreciation. The adjusted basis of that portion of the casing and associated downhole equipment left behind in the well is deductible as a loss under IRC 165 and the associated regulations.

  2. The ruling does not state that equipment such as separators, storage tanks or a pipeline must be available to accept production for a well to be considered placed-in-service. Oil and gas wells may stand idle for a period of time while such assets are being constructed by the taxpayer or by third parties such as a pipeline company.

4.41.1.3.2.4.2  (12-03-2013)
MACRS Class Lives and Recovery Periods

  1. Refer to Exhibit 4.41.1-43 which compiles the MACRS class lives and recovery periods for assets used by companies in the various business segments of the oil and gas industry. The majority of the information is from Rev. Proc. 87-56, IRB 1987-2 CB 674.

4.41.1.3.2.5  (07-31-2002)
Joint Owner Accounting

  1. A large number of oil and gas leases are owned and operated by two or more persons as "joint owners." The Council of Petroleum Accountants Societies (COPAS) has published a series of bulletins that serve as a standard for accounting practices recommended for the petroleum industry. The COPAS Bulletins provide a standard method for joint owner accounting, wherein an operator must account for all of the income and expenditures to all of the other nonoperating interest owners in the form of a summary billing. The format and content of the billing must be such that the nonoperating interest owners can maintain their records properly from the advice given them by the operator.

4.41.1.3.2.6  (07-31-2002)
Joint Billing

  1. Joint billing of the lease operating and development costs by the operator to the other nonoperator interest owners will identify the property and provide a summary of all expenditures and income (unless the purchaser of the production remits direct to the nonoperator interest owner) broken down by capital expenditures, intangibles, and operating expenses. The operator who is also part owner of the working interest will prepare a monthly summary billing of the total lease operating cost and bill the other working interest owners for their share. The accounting entries involved are to credit the various expense accounts involved and debit accounts receivable. This should involve only actual expenses. The overhead or other service charges that are made to the other working interest owners should not be included in the credit to the expense accounts. Instead, it should be credited to a revenue account. Larger taxpayers will generally maintain a separate set of books for joint owner accounting.

4.41.1.3.2.7  (07-31-2002)
Offset Against Income

  1. There are different ways by which the revenue from the property will be paid to the various owners. In the usual situation, the purchaser of the production will remit the revenue directly to the working interest owners, royalty interests, overriding royalty interests, and production payment interests. In some cases the purchaser will remit 100 percent of the revenue to the operator (called a 100 percent division order). It then becomes the operator's obligation to pay each interest owner their share.

  2. The practice of offset against income can arise in joint owner accounting where the purchaser remits all the working interest owners' share of revenue to the operator. This most generally arises in drilling funds where many of the owners are merely investors.

  3. The IRS has published rulings (Treas. Reg. 3930, 1948–2 CB 126, and Treas. Reg. 3948, 1949–1, CB 161) approving the concept of joint operation of oil and gas properties under agreements, with the cited characteristics, and not to be classified as an association taxable as a corporation. Refer to the rulings for the specific characteristics; but, in general, if there is no joint sale, there can be no joint profit and hence no association taxable as a corporation. The concept of Treas. Reg. 3930 and 3948 were embodied in IRC 761(a)(2) and Treas. Reg. 1.761–2(a)(3). Also see IRM 4.41.1.3 (7).

4.41.1.3.2.8  (07-31-2002)
Dispersal Account or Oil and Gas Payout Account

  1. The dispersal account is associated with the revenue received by the operator for the account of the joint interests. This account is treated as a clearing account—as the income is remitted to the other interest owner it should zero out.

  2. The dispersal account is one that should always be analyzed to determine if it is clearing out or building up a balance. If it is building up a balance, it probably means that income is not being reported by some entity. The most likely prospect is some entity related to the operator. In any event, the reason for the buildup in the account should be ascertained and appropriate action taken.

  3. The joint operating agreement should be secured in those instances when it appears necessary to know the provisions, rights, and obligations of all parties to the joint operating agreement.

  4. If the operator is also a promoter and the joint operation is more in the nature of a drilling fund, look for instances where the operator will buy back an interest in the property and charge it off to development costs through the joint operation expense accounts.

  5. To determine if there exists any carried interest, production payments, or unusual arrangements concerning the allocation of development costs or operating expenses, examine the percentages of income and expense going to the various interests compared to their percentage interest in the property.

4.41.1.3.2.9  (12-03-2013)
Future Liabilities for Well Plugging, Platform Dismantlement, and Property Restoration

  1. The operator of an oil well or an offshore platform is obligated by regulations and/or its lease to perform certain tasks when its assets reach the end of their useful lives. Wells must be plugged and abandoned. Any earthen pits that contained waste products from drilling or production operations must be either sealed or emptied. Offshore platforms must be removed so they don’t become a hazard to navigation. The term "dismantlement, removal and restoration" (DR&R) is often used to encompass all of these obligations.

  2. For financial accounting purposes, public companies must estimate the amount of their future DR&R obligations and make appropriate entries on their financial statements. As evidenced by Rev. Rul. 80-182, 1980-2 CB 167, the Service’s long-standing examination position is that "estimated future" DR&R costs may not be deducted (i.e., a deduction is only allowed when the DR&R activity takes place).

  3. As background, in the 1970's and 1980's the Service’s position was successfully challenged by a number of mining companies. In response, IRS Appeals created a coordinated settlement position which allowed 25-year amortization of estimated DR&R costs for domestic offshore platforms located in water depths of less than 500 feet and placed in service before mid-1984. Similarly, amortization of the estimated DR&R liability of the Trans-Alaska Pipeline was allowed for its original owners. See United States v. ConocoPhillips Co., 2012 U.S. Dist. LEXIS 119339, 110 A.F.T.R.2d (RIA) 5628, 2012-2 U.S. Tax Cas. (CCH) P50535 (N.D. Okla. 2012). Such settlements generally require the "restoration to income" of previously amortized amounts in two circumstances:

    • when the taxpayer is relieved of the DR&R liability (e.g., by sale of the asset)

    • when DR&R actually takes place and the taxpayer incurs out-of-pocket costs

  4. The Service’s position as reflected in Rev. Rul. 80-182 was essentially codified with the enactment of the Economic Performance rules of IRC 461(h) in 1984. Since DR&R is normally performed by service providers, IRC 461(h)(2)(A) would permit a deduction only when DR&R services are performed. However, examiners should be aware of the following potential issues:

    1. Taxpayers improperly recovering (over time) estimated DR&R costs via additions to basis for depletion, depreciation, or amortization. Examiners should make sure the taxpayer has reversed out all such deductions or basis additions that were included or expensed for financial accounting purposes.

    2. Taxpayers failing to properly "restore to income" any previously amortized amounts at the time the DR&R actually occurs or when they are relieved of the liability.

    3. Deducting the full amount of premiums paid for surety bonds when part of the premium is essentially a refundable deposit for future DR&R. Surety bonds are often required of "thinly capitalized" oil companies that install offshore platforms in federal waters. Annual insurance premiums are generally deductible. However, some surety arrangements consist of both a surety policy and an escrow account. Contributions to an escrow account are generally not deductible because they are refundable if the policy is cancelled.

    4. "Guarantee fees" paid to a foreign parent. The U.S. Department of Interior will generally impose the DR&R obligation on the original lessor of federal land whenever a sublessor fails to perform its obligation. Consequently, the transferor of a federal oil and gas lease will often require (by contractual obligation) the transferee to maintain adequate financial reserves to perform DR&R, or to obtain the guarantee of a parent corporation. Examiners may find U.S. taxpayers improperly deducting "fees" paid to their foreign parent to "guarantee" performance of DR&R on behalf of its subsidiary. Such payment should not be allowed as a deduction because in substance it represents a mere deposit of funds with the parent corporation.

  5. Economic performance rules for liabilities that are assumed in the sale of a trade or business are specifically addressed by Treas. Reg. 1.461-4(d)(5). If the buyer expressly assumes the liability in the sale of trade or business that the seller but for the economic performance requirement would have been entitled to incur as of the date of the sale, economic performance with respect to that liability occurs as the amount of the liability is properly included in the amount realized by the seller upon the sale. If an examiner determines that a taxpayer utilized this regulation in the context of selling assets subject to future DR&R liabilities, then the liabilities should be reviewed and discussed with Local Counsel or a Subject Matter Expert.

4.41.1.3.3  (12-03-2013)
Secondary and Tertiary Recovery Methods

  1. The production of crude oil from a reservoir is often viewed as occurring via recovery methods that occur in phases (e.g., primary, secondary and tertiary recovery methods).

    • Primary recovery relies on the inherent energy in the reservoir to allow wells to produce fluids in the reservoir to the surface, and pumps to lift fluids from those wells when the reservoir energy is insufficient

    • Secondary recovery methods generally involve the injection of water or natural gas into the reservoir to increase or maintain its pressure, or to displace oil towards producing wells without causing significant chemical or physical changes to the oil

    • Tertiary recovery methods generally cause a significant chemical or physical change to the oil (other than just an increase in pressure). An example is the introduction of heat into the reservoir in order to lower the viscosity (thickness) of the oil which in turn allows it to more readily flow towards producing wells. "Tertiary recovery" is a term that has been used in the industry for several decades. IRC 193 contains a definition that is specific to incentives in the Code and references qualified tertiary recovery methods such as

    • Miscible fluid displacement

    • Steam drive injection

    • Microemulsion or micellar/emulsion

    • In situ combustion

    • Polymer augmented waterflooding

    • Cyclic steam injection

    • Alkaline (or caustic) flooding

    • Carbon dioxide augmented waterflooding

    • Immiscible carbon dioxide displacement

    • Any other method to provide tertiary enhanced recovery which is approved by the secretary for purposes of IRC 193

  2. The use of horizontal drilling in conjunction with reservoir fracturing has become very common in recent years and has resulted in very significant production of oil and natural gas. However, those are drilling and completion techniques that allow the production of oil and gas via primary and other recovery methods.

  3. Secondary and tertiary recovery methods of oil recovery may be instituted at any time during the economic life of an oil field. The implementation usually occurs after the entire field has been developed and primary recovery has occurred for a number of years. Information gained during development and production operations is very important in optimizing the design of subsequent recovery methods.

  4. A successful secondary or tertiary recovery program involves a plan wherein water, gas, or some other fluid will be injected into the oil bearing formations and force the oil into the bore holes in order that it may be pumped out. This may involve the drilling of injection wells and additional oil wells. The injection wells may be located on the perimeter of or interspersed in a pattern throughout the oil field in order to drive the oil through the formation to the oil wells. Because of the need for a plan involving an entire field, several owners may be involved. Hearings before the state conservation commission are likely to be required to gain approval of the plan. Unitization of ownership interests will also likely be required.

4.41.1.3.3.1  (12-03-2013)
Waterfloods and Gas Pressure Maintenance

  1. The most common method of secondary recovery is water flooding. Waterfloods will usually require the drilling of additional oil wells and injection wells that will fit a pattern designed to produce the maximum oil. The drilling costs of both the injection and oil wells are deductible as IDC if the taxpayer has made the proper election under IRC 263(c). Tangible equipment is required to be capitalized and depreciated in the same manner as if the wells were being drilled for primary production.

  2. A common method in use is the five-spot pattern where one producing well will remain in the center of four water injection wells. Usually some of the producing wells will be converted to water injection wells.

  3. Another common secondary recovery method is the injection of natural gas into an oil reservoir in order to maintain reservoir pressure which in turn improves oil recovery. See IRM 4.41.1.3.9.7 for potential issues.

4.41.1.3.3.2  (12-03-2013)
Operating Costs

  1. Operating costs are usually somewhat higher when secondary recovery methods are employed because of the added expense of injecting the water or gas into the formation under pressure requiring the operation of pumps, compressors and other equipment using energy. The water that is pumped out with the oil must also be handled. However, the operating expenses are deductible in the same manner as primary production.

4.41.1.3.3.3  (07-31-2002)
Water Supply Wells

  1. Water supply wells that are drilled for the principal purpose of furnishing a water supply for the injection wells are required to be capitalized and depreciated. Wells that are drilled for the principal purpose of supplying water used in the drilling of oil and gas wells come within the option of IRC 263(c) to charge to expense IDC.

4.41.1.3.3.4  (07-31-2002)
Water Injection Wells

  1. Water injection wells may be new wells drilled to satisfy a pattern needed for the waterflood plan, or they may be old oil wells that are converted to water injection wells. In the case of new wells drilled for the purpose of water injection for secondary recovery purposes, taxpayers may elect to expense the intangible drilling costs under the option contained in IRC 263(c). The court has ruled on the issue in Page Oil Co. 41 BTA 952 and held that the option applied; the Commissioner, however, non-acquiesced. For a limited exception to this view, see Rev. Rul. 69–583, 1969–2 CB 41. This ruling provides that certain costs incurred in drilling water injection wells necessary in the primary development of an oil property are "intangible drilling and development costs" and may, at the taxpayer's option, be chargeable to capitalize or to expense. In TAM 8728004, 3-18-1987 the Service concluded that cost incurred drilling injection wells were eligible for treatment under IRC 263(c) and Treas. Reg. 1.612–4. See also GCM 39619.

4.41.1.3.3.5  (12-03-2013)
Salt Water Disposal Wells

  1. Salt water disposal wells are required by most state regulatory agencies if salt water is produced with the oil. It must be separated from the oil and disposed of by being injected into a salt water disposal well. Most states have strict rules concerning the disposal of salt water and require operators to agree to certain specifications for the drilling and equipping of salt water disposal wells. Refer to Rev. Rul. 70-414, 1970-2 CB 132.

  2. The problems encountered in auditing a waterflood secondary recovery operation are that certain drilling costs do not come within the option to charge to expense the IDC. The drilling of salt water disposal wells and water supply wells, if drilled for the principal purpose of acquiring a water supply for injection into the producing formation, does not come within the option. The taxpayer's records and vendor's invoices may merely reflect drilling expense, and it is not easily determined what kind of well is being drilled.

  3. There are two resources that may help the examiner identify or discover that a water supply well or salt water disposal well has been drilled. If the taxpayer is an operator, an oil field map identifies the location and number of all wells. Usually, fresh water wells and salt water disposal wells can be identified from such a map. In addition, most state regulatory agencies require a permit to be secured before the well can be staked and drilling started in which case the operator would have a copy of the application, giving all of the information needed for a determination of the type of well drilled.

  4. It is not unusual for a taxpayer to convert an old oil well or dry hole to a salt water disposal well, and there is probably not much that can be done about the drilling costs being expensed as IDC (assuming the taxpayer's stated intentions correspond to his/her actions). However, there are usually additional drilling and completion costs associated with the conversion of an oil well or dry hole to a salt water disposal well. These may be identified by a review of the application with the state regulatory agency for the conversion. The application will list the numerous specifications and work that will be done to comply with the state's specifications for the conversion.

4.41.1.3.3.6  (12-03-2013)
Other Costs

  1. The tax treatment of all types of secondary and tertiary recovery methods is virtually the same. One common characteristic is that all methods require specialized equipment such as pumps, tanks, boilers, high pressure wellhead equipment, filters, etc. This type of tangible equipment must be capitalized and depreciated. The expense of operating the secondary or tertiary recovery system such as power, utilities, chemicals, repairs, labor, depreciation, etc., are deductible as part of the lease operating expense.

  2. There are specific rules in IRC 193 for "qualified tertiary injectant expenses." For income tax purposes, IRC 193(a) requires that a taxpayer be allowed as a deduction for the taxable year an amount equal to the qualified tertiary injectant expenses of the tertiary injectants injected during such year. For purposes of IRC 193, the term "qualified tertiary injectant expenses" means any cost paid or incurred during the taxable year (whether or not chargeable to capital account) for any tertiary injectant (other than a hydrocarbon injectant, which is recoverable) which is used as a part of a tertiary recovery method. The term "hydrocarbon injectant" includes natural gas, crude oil, and any other injectant which is comprised of more than an insignificant amount of natural gas or crude oil. With respect to this deduction, there is no election. A taxpayer is required to take the allowable deduction.

  3. IRC 193 is interpreted in Treas. Reg. 1.193-1. An examiner should study this regulation carefully before making a tax decision with respect to hydrocarbon injectants.

  4. Examiners should be aware that some taxpayers have improperly claimed that the capital cost of tangible equipment which handles tertiary injectants (such as carbon dioxide pipelines) is currently deductible under IRC 193 as a tertiary injectant expense. Taxpayers' position is primarily based on language found in Rev. Rul. 2003-82, 2003-2 C.B. 125, which was issued with respect to the IRC 43 Enhanced Oil Recovery tax credit. That ruling states that for purposes of IRC 43(c)(1)(C), the definition of "qualified tertiary injectant expenses" includes expenditures related to the use of a tertiary injectant as well as expenditures related to the acquisition (whether produced or acquired by purchase) of the tertiary injectant. However, the ruling did not extend the definition beyond costs which would be deductible expenses. The day-to-day cost to operate a CO2 pipeline can constitute an IRC 193 tertiary injectant expense, but not the capital cost of the pipeline. The Service's reasoning is explained in PLR 201117028.

4.41.1.3.4  (01-01-2005)
Enhanced Oil Recovery Tax Credit

  1. IRC 43 was enacted in 1990 to provide an investment credit for certain costs paid or incurred with respect to qualified Enhanced Oil Recovery (EOR) projects. The amount of the credit is generally equal to 15 percent of qualified expenditures made by the taxpayer and becomes part of the general business credit. The credit is claimed on IRS Form 8864.

  2. The EOR credit has a "phase out" provision that will reduce or eliminate the rate of the credit whenever oil prices in the U.S. rise above $28 per barrel (adjusted for inflation after 1990). IRS Notice 2013-50, IRB 2013-32 IRB 134 explains that:

    • No "phase-out" occurred in calendar years 1991 through 2005

    • 100 percent "phase-out" occurred in 2006-2013

  3. Generally, the EOR credit is only available for projects that employ certain tertiary recovery methods, unless the IRS approves an additional recovery method via a revenue ruling or a private letter ruling. The projects must be located within the U.S. and have commenced after December 31,1990. There is an exception for "significant expansions" of projects that began before 1991.

  4. Starting in 2005 the EOR credit was extended to costs to construct a gas treatment plant capable of processing certain Alaska natural gas for transportation through a pipeline with a capacity of at least two trillion BTU of natural gas per day. To qualify, the gas treatment plant must also produce carbon dioxide which is injected into a hydrocarbon-bearing geological formation.

  5. A self-certification process is mandated by the statute. The operator of each EOR project (or its designee) must file a certification from a registered petroleum engineer stating that the project meets certain criteria. Afterwards, a continuing certification is filed annually. IRS Form 8864 directs taxpayers to file all certifications with the Ogden Campus. The petroleum technical subject matter experts are responsible for maintaining the inventory of the certifications. When a certification appears to lack information required by the regulations, the technical subject matter experts will notify the examination team for taxpayers under continuous audit, and will directly contact other taxpayers.

  6. The expenditures which will qualify for the IRC 43 tax credit generally consist of tertiary injectant expenses, tangible property costs, and intangible drilling costs (IDC). For purposes of the EOR credit, tertiary injectant expenses must be described in IRC 193 and deductible during the taxable year under any code section. Refer to Rev. Rul. 2003-82, 2003-2 CB 125. The at-risk limitation rules of IRC 465 apply. On a year-by-year basis taxpayers may decide whether or not to claim the credit. When the credit is claimed, the taxpayer must reduce its deductions and/or basis of those items which comprise the qualified expenditures by the amount of the credit.

  7. Many EOR projects are operated by joint ventures and the operator will frequently notify the non-operators as to the annual expenditures for qualified costs. When an examiner has reviewed a project in sufficient detail to determine the merits of the project and the associated major expenditures, the following steps should be taken:

    • Secure the identity of the operator, each working interest owner, and the working interest percentage of all parties

    • Request a copy of any information letter supplied to or from the operator regarding the amount of qualified costs

    • Provide the forgoing information and a synopsis of the examiner’s determination to the petroleum technical subject matter experts who are responsible for forwarding the examiner's determination to the other examination teams for their consideration.

  8. The Enhanced Oil Recovery Tax Credit is no longer a tier issue per LB&I Directive 4-0812-010.

  9. Reviewing the qualification of an EOR project or the associated costs requires specialized knowledge of petroleum operations. Agents should consider requesting the services of a petroleum engineer.

4.41.1.3.5  (12-03-2013)
IRC 45Q Credit - Sequestration of Carbon Dioxide in Enhanced Oil or Natural Gas Project

  1. A recently added General Business credit, IRC 45Q, provides a tax credit for qualified carbon dioxide (CO2) that is captured and disposed of in secure geological storage (sequestered). Generally, the credit is allowed to the entity or person that captures and physically or contractually ensures the disposal of the qualified CO2.

  2. The credit rate is:

    • $20 (adjusted for inflation for tax years beginning after 2009) per metric ton for qualified CO2 captured at a qualified facility, disposed of in secure geological storage, and not used as a tertiary injectant in a qualified enhanced oil or natural gas recovery project (EOR project); and

    • $10 (adjusted for inflation for tax years beginning after 2009) per metric ton for qualified CO2 captured at a qualified facility, disposed of in secure geological storage, and used as a tertiary injectant in an EOR project.

  3. For the purpose of calculating the credit, a metric ton of CO2 includes only the contained weight of the CO2. The weight of any other substances, such as water or impurities, is not included in the calculation. Only CO2 captured and disposed of, or used as a tertiary injectant within the United States or a U.S. possession and later disposed of in secure geological storage, is taken into account.

  4. Some definitions are specific to this credit:

    • Qualified CO2 is CO2 captured after October 3, 2008, from an industrial source that would otherwise be released into the atmosphere as an industrial emission of greenhouse gas, and is measured at the source of capture and verified at the point of disposal or injection. Qualified CO2 also includes the initial deposit of such captured CO2 used as a tertiary injectant in an EOR Project. It does not include CO2 that is re-captured, recycled, or otherwise re-injected as part of the EOR Project.

    • A Qualified Facility is any "Industrial Facility" that is owned by the taxpayer where carbon capture equipment is placed in service and that captures at least 500,000 metric tons of CO2 during the tax year.

    • An Industrial Facility is a facility that produces a CO2 stream from a fuel combustion source, a manufacturing process, or a fugitive CO2 emission source that, absent capture and disposal, would otherwise be released into the atmosphere as an industrial emission of greenhouse gas. An industrial facility does not include a facility that produces CO2 from CO2 production wells at natural carbon-dioxide-bearing formations.

      Note:

      "CO2 production wells" and "natural carbon dioxide-bearing formation" have not yet been defined. Local Counsel should be consulted if the CO2 concentration of a source gas is sizeable.

    • Secure Geological Storage includes storage of the captured CO2 at deep saline formations, oil and gas reservoirs, and unmineable coal seams under such conditions as the IRS may determine under regulations.

  5. The credit is claimed on Form 8933 - Carbon Dioxide Sequestration Credit. Examiners should review the instructions to the form and also Notice 2009-83, 2009-2 CB 588. Section 6 of the Notice requires taxpayers that claim the credit to file an annual report with the IRS Office of Chief Counsel. Examiners should obtain a copy of the statement and written confirmation by the taxpayer that the information contained in the report is still correct, especially the identity of any contractually ensuring party. A referral to an IRS engineer should be considered.

  6. One attribute of a qualified EOR project is that the operator has submitted a Petroleum Engineer’s Certification to the Ogden Service Center. If the taxpayer asserts that the CO2 which it captured is being used as a tertiary injectant in an EOR project, examiners should obtain a copy of the certification and review it for pertinent facts.

  7. If a taxpayer claims the IRC 45Q credit based on the contractual assurance that another party will sequester the CO2 in secure geologic storage, a copy of the contract between the parties should be obtained and inspected to verify such assurance exists. If such assurance does not exist, but the parties are renegotiating the contract to include it, the examiner should contact local IRS Counsel for advice on how to proceed. In the event the contract does not provide appropriate contractual assurance, the tax credit should be disallowed. If any credit was claimed in previous tax years, the examiner should contact local IRS Counsel regarding recapture of those amounts.

  8. IRC 45Q and Notice 2009-83 state that a taxpayer claiming the credit must comply with evolving rules of the U.S. Environmental Protection Agency (EPA) regarding the sequestration of CO2 and reporting of CO2 volumes measured at the source of capture and verified at the point of disposal or injection.

  9. EPA promulgated final rules regarding the reporting of both CO2 emissions and CO2 use (including sequestration) for years after 2010. Subpart RR - Geologic Sequestration of Carbon Dioxide is applicable to the IRC 45Q credit. Refer to http://www.epa.gov/ghgreporting/reporters/subpart/rr.html

  10. The Preamble to EPA’s final rule states in plain language that, under the final rule, operators of facilities that are sequestering CO2 in geologic storage must comply with Subpart RR regardless of whether the CO2 is currently used as a tertiary injectant in an EOR project. EPA’s preamble also states that taxpayers claiming the 45Q tax credit after 2010 must follow Subpart RR’s "MRV procedures" . MRV stands for Monitor, Report and Verify. The MRV procedures require the operator to submit an MRV plan to the EPA for its approval, and to annually report CO2 volumes, including amounts sequestered, pursuant to the plan. Examiners should obtain a copy of these documents.

  11. Tax credits claimed by the taxpayer in years after 2010 should be reconciled with annual volumes reported by the operator of the facility to the EPA under its subpart RR rules. If a taxpayer has claimed the tax credit for current or prior years, but the operator did not submit an MRV plan to the EPA for activity for years beginning after 2010, the examiner should contact local IRS Counsel and Petroleum Subject Matter Experts regarding the treatment of those previously or currently claimed credits.

4.41.1.3.6  (12-03-2013)
Nonconventional Source Fuels Credit

  1. IRC 29, renumbered IRC 45K and made part of the general business credit with enactment of Tax Incentives Act of 2005, authorizes an income tax credit for the production of certain non-conventional fuels. The IRC 29 credit is generally equal to $3.00 multiplied by the number of "barrel-equivalents" of qualified fuel that is produced and sold by the taxpayer to unrelated persons. When a fuel-producing property is owned by more than one taxpayer, production is generally allocated based upon each taxpayer’s interest in gross sales. Treas. Reg. section 1.761(d) provides specific rules for gas producers that produce natural gas under joint operating agreements.

  2. Qualified fuels include:

    • Oil production from oil shale and tar sands

    • Gas produced from geo-pressured brine, Devonian Shale, coal seams, tight sands, biomass, and

    • Liquid, gaseous and solid synthetic fuels from coal (including lignite)

  3. The credit for these fuels has both a drilling window (generally from 1-1-80 through 12-31-92) and a production window (from 1-1-1980 to 12-31-2002). Thus, except for production in 2002 for which a taxpayer claims a credit, this issue no longer exists after 2002.

  4. Because of the technical nature of the issue, IRC 29 credit is usually worked by the Service’s engineers.

4.41.1.3.6.1  (12-03-2013)
Qualifying Wells and FERC’s Role

  1. Determination that a well is producing gas from a geo-pressured brine, Devonian Shale, coal seam, or tight sand is made in accordance with Section 503 of the Natural Gas Policy Act of 1978 (NGPA). The Federal Energy Regulatory Commission (FERC) http://www.ferc.gov/administers the NGPA. The courts have ruled that FERC must provide a "final well category determination" before the production can qualify for the credit. See True Oil Co. vs. Commissioner, 83 AFTR 2nd, Par. 99-357, No. 97-9029, No. 97-9030 (March 23,1999).

  2. In mid-1993 the FERC discontinued providing these determinations for wells that had been drilled before January 1, 1993. FERC Order No. 616, issued July 14, 2000, amended its regulations to reinstate provisions for making well category determinations under Section 503 of the NGPA. This FERC order extended provisions to all wells spudded before January 1, 1993 and re-completions both before and after that date. It also provided for the designation of new tight gas formation areas. The petroleum technical subject matter experts can assist with locating wells on FERC’s databases.

  3. Examiners should be aware that the mere fact that FERC provided a final well determination does not mean that the well meets all the criteria of IRC 29.

  4. Prior to November 5, 1990, IRC 29 also required that the price of the gas be regulated under the NGPA. Responding to the phased-in decontrol of wellhead prices under the Natural Gas Wellhead Decontrol Act of 1989, as part of the Omnibus Reconciliation Act of 1990 (OBRA of 1990), Congress removed that requirement. Thereafter, Congress provided that to qualify for the credit, a tight formation well must be on land committed or dedicated to interstate commerce as of April 20, 1977 or must be drilled after the date of enactment of the OBRA (November 5, 1990). See IRC 29(c)(2)(B).

  5. In Rev. Rul. 90-70 the Service established that for initial completions, the well's spud date will generally be considered as determining the date the well is drilled for purposes of IRC 29. Rev. Rul. 93-54 holds that for "re-completions" after 1992 from wellbores drilled (spudded) between December 31, 1979 and January 1, 1993 will qualify as long as the re-completion does not involve deepening the well. The Service’s informal position on re-completions of wells spudded prior to 1980 is reflected in various Private Letter Rulings (PLR's 9025002, 9027005, and 9253050). These PLR’s provide that for re-completions between December 31, 1979 and January 1, 1993 into new qualifying zones, the re-completion date will determine the date "drilled " .

4.41.1.3.6.2  (01-01-2005)
Computing the Credit

  1. The credit is initially calculated as $3 for each barrel-of-oil equivalent ("BOE" ) of qualified fuel. A BOE is defined as fuel that has a Btu (British Thermal Unit) content of 5.8 million. A cubic foot of gas contains about 1000 Btu, thus, 5.8 thousand cubic feet ("MCF " ) of natural gas has nearly the same number of Btu’s as one BOE. Therefore the credit is approximately $0.5172 per MCF ($3.00 divided by 5.8). All operators and most royalty owners should have access to the heat content of the gas produced from their property.

  2. The credit is adjusted (reduced) by an amount equal to the product of

    • Initial credit, and

    • A fraction equal to the amount that the "reference price for the calendar year in which the tax year begins" exceeds $23.50 ÷ $6.00. Mathematically, it can be given as follows:

      $3 - [ (Ref.Price-$23.50)/6 × $3]

  3. The initial credit amount of $3, the $6 divisor and the $23.50 are indexed and adjusted yearly for inflation. However, for gas produced from a "tight formation" the $3 figure is not adjusted for inflation. Examiners should not be concerned with using the formula to compute the per-BOE credit amount. The Service publishes the reference price, inflation factor, and credit amount in early April each year for the preceding year. Information from Notices 2000-23, 2001-31, 2002-30, 2003-27 and 2004-33 is as follows:

    Calendar Year Inflation Adjustment Factor Reference Price Credit Amount (Per BOE) Credit Amount for Gas from Tight Formations (Per BOE)
    1999 2.0013 $15.56 $6.00 $3.00
    2000 2.0454 $26.73 $6.14 $3.00
    2001 2.0917 $21.86 $6.28 $3.00
    2002 2.1169 $22.51 $6.35 $3.00
    2003 2.1336 $27.56 $6.40 $3.00

  4. The IRC 29 credit is both reduced and limited in any year. The credit is reduced first by the following amounts:

    • A pro-rata portion of the credit generated through special financing arrangements

    • Any portion of the credit financed through grants from Federal, State or a political subdivision of state entities

    • Proceeds from state or local obligations used to finance the project if the interest from those bonds is exempt from tax under IRC 103

    • IRC 48(a)(4)(C) subsidized energy financing

    • IRC 48 energy credits

    • IRC 43 enhanced oil recovery credits

  5. The IRC 29 credit (after the above-mentioned adjustments) is limited in any year to the excess of the taxpayer’s regular tax, reduced by the sum of the credits allowable under Subpart A, Non-Refundable Personal Credits and IRC 27, over their tentative minimum tax (" TMT" ).

4.41.1.3.6.3  (01-01-2005)
Monetization of IRC 29 Credits

  1. An industry practice that started in the early 1990’s was to monetize or, in effect, sell the rights to the tax credits. This is advantageous for taxpayers with substantial credits that were of no benefit to them because of their tax situation. A taxpayer in an AMT position and from future projections will be an AMT for years to come, the credits would be of marginal value. Therefore many taxpayers decided to transfer the right to the credits for cash and monetize the credit.

  2. Because many non-conventional fuel producers cannot utilize the full value of their tax credits, they have structured themselves so they have the ability to transfer these credits to other parties. One such arrangement is the direct purchase of the tax credits from the source of production. This is apportioned with respect to allocated interests in the tax credits derived from the production of gas. Under this arrangement, each ownership interest is allocated tax credits according to their participation in the gas produced and the associated tax credits for that year. These tax credits are then entered directly on the investor's Form 1040, as described in the Form 1040 instructions. Another strategy has been the royalty trust, where each member of the trust acquires a non-operating net profit interest in the property. Tax credits available for fuel produced on the property are then allocated to the members in proportion to their interest in the royalty trust. There are currently eight publicly traded oil and gas royalty trusts that pass non-conventional fuels tax credits to investors. To some degree it is now possible for an individual to purchase the right to tax credits needed on a yearly basis.

  3. Even more complex are transactions where a producer will notionally sell the economic interest in the mineral property to another taxpayer for cash and one or more production payments. Examiners should be aware that the Service has issued many private letter rulings (PLR) regarding these monetization transactions, which are usually quite complex. The examiner should require the taxpayer disclose any PLR it received. After reviewing the PLR, the examiner may decide to focus on whether the taxpayer has executed the transaction in accordance with the way it was described in the submission for a PLR.

4.41.1.3.6.4  (01-01-2005)
Typical Audit Steps

  1. Determine the IRC 29 credit claimed for each tax year.

  2. Discuss the limitations of the AMT with a technical specialist.

  3. Request a list of the claimed credit by well. Specific information that should be provided for each well includes –

    • Well identification (name, location, and API number)

    • Producing formation

    • Type of qualified fuel

    • Volume of gas produced and sold during the year

    • Number of Btu’s claimed for the credit and/or the Btu conversion factor

    • Credit

  4. Review the list to determine which wells will be closely reviewed.

  5. Verify that the well has received a final well determination from FERC.

  6. The following items can often be verified by using publicly available data such as IHS Energydata -

    • Was the well drilled or re-completed during the appropriate window?

    • Was the well drilled into the same proation unit as another well?

    • Verify that the well was not completed into another geologic formation after receiving its final well determination from FERC. These determinations are specific to a completion, not a well.

    • Verify that gas from the well was being sold to an unrelated party.

  7. If more than one taxpayer owns an interest in the well, verify that the credit is being apportioned based on gross sales. Be sure that a working interest owner is not claiming the credit on production which is attributable to royalty owner(s).

4.41.1.3.7  (12-03-2013)
Marginal Well Credit

  1. American Jobs Creation Act of 2004 Income Tax Provisions created new code section IRC 45I , Credit for Producing Oil and Gas from Marginal Wells. The provision creates a new $3 per barrel credit for qualified crude oil production and 50 cents per 1,000 cubic feet of qualified natural gas production. The term qualified production means domestic crude oil or natural gas produced from a qualified marginal well. In case of production from a qualified marginal well which is also eligible for the Nonconventional Fuel Source Credit allowed under IRC 45K, the taxpayer can claim the 45I credit only if it elects to not claim the IRC 45K credit. Refer to IRC 45I(d)(3).

  2. Qualified production must be treated as marginal production under IRC 613A(c)(6) or on an annual basis the well must have an average daily production of not more than 25 BOE and must produce water at a rate of not less than 95 percent of its total fluid output.

  3. This credit is available for production in taxable years beginning after December 31, 2004 and is a component of the general business credit subject to 5 year carry-back and 20 year carry-forward for any unused credits.

  4. This credit is not available to production when the reference price of crude oil exceeds $18 and the price of natural gas exceeds $2. The credit is reduced proportionately as the reference price ranges between $15 and $18 for crude oil and $1.67 and $2 for natural gas. Due to the current price of crude oil and natural gas, this section will not have an immediate effect on examinations.

4.41.1.3.8  (07-31-2002)
Equipment Inventory

  1. The accounting for the individual owner-operator and the jointly owned oil and gas operating properties sometimes presents problems, especially regarding the accounting for the transfers of depreciable equipment between the lease equipment account and equipment inventory account.

  2. The individual who owns and operates his/her own oil and gas leases usually makes transfers from the producing lease equipment account to the inventory account at the fair market value of the used equipment at the time of the transfer. The COPAS Bulletins specify methods of valuation to be used. These methods generally provide for a value as a percent of new replacement cost based upon the condition of the used equipment. This value is normally used because the historical cost of the individual item of equipment is difficult to identify. If there is a large piece of equipment transferred and the original cost can be identified, it would be transferred at cost. The equipment inventory account is debited with this value or cost, and the lease equipment account is credited with the same amount. The depreciation reserve account is normally not disturbed, except for the depreciation on the equipment that is transferred at cost. Generally, no depreciation is claimed on the inventory account. This inventory equipment is on standby to be placed back into active service when it is needed. This method of accounting for the equipment transfers is normally not disturbed if the taxpayer uses this method consistently, and its use does not materially distort income. If the taxpayer makes sales of the equipment, then the gain or loss on the sale should be recognized at that time. The original cost less depreciation will be used in computing gain. Transfers from the inventory account to the lease equipment account are made at the same value. If there are purchases of equipment from outsiders and charged to the inventory account, those transfers out are usually made at cost, since the cost can be identified.

  3. The accounting for the equipment transfers on a jointly owned lease where the joint owner-operator does not take ownership of the equipment inventory account is similar to that of the individual owner. The transfers to the inventory account from the lease equipment account are usually made at cost, if cost is available, or at the fair market value of the equipment at the time of the transfer. The joint operating agreement between the joint owners and the lease operator will normally specify the method of transferring assets—see operating agreement in COPAS Bulletins. See below for the discussion of values placed on equipment by the operating agreement. The ownership of the inventory account is important because there has not been a disposition of the equipment if the joint owners retain ownership of the inventory account. It should be remembered that the taxpayers method of accounting for the equipment transfers will not be disturbed if the use of the method is consistent and its use does not materially distort income.

  4. The accounting for the equipment transfers on jointly owned leases where the operator is an outside third party presents fewer problems. Since a change in the ownership of the equipment takes place every time there is a transfer, gains and losses must be computed on each transfer. See IRM 4.41.1.3.8.1 for a full discussion of this problem and its relation to the operating agreement.

4.41.1.3.8.1  (07-31-2002)
Provisions of Operating Agreement

  1. The accounting for the equipment transfers on jointly owned leases where the joint owner-operator owns the equipment inventory account and buys and sells equipment from and to the joint owners through this account is unique. The operating agreement generally provides that equipment transferred from the lease equipment account to the inventory or warehouse account is graded according to the condition of the equipment. Normally, the grade of the equipment is either new, A, B, C, D, or junk, and carries a value equal to a percentage of new equipment cost. Grade A equipment is valued at 90 to 100 percent of new cost, Grade B at 75 to 80 percent, etc. The joint owners are given credit or charged on their monthly joint billings for any equipment transferred to or from the inventory account. These transfers to the inventory account constitute dispositions of property, and gains or losses on each transfer should be recognized. Transfers from the inventory account constitute purchases of equipment. The transfers to and from the inventory or warehouse account sometimes present problems. The taxpayer's method of accounting will normally not be disturbed if it accounts for gains and losses, is consistently used and does not distort income.

4.41.1.3.8.2  (07-31-2002)
Gain or Loss on Inventory

  1. The gains and losses on the transfers of equipment should be recognized when the ownership of the property changes on the transfer. Most transfers to the inventory account are made at the price provided for in the operating agreement. This sale price is easily ascertained since it can be found on the monthly joint billings. The taxpayer's cost basis in the equipment transferred from the oil and gas leases is sometimes impossible to ascertain. When the tax cost cannot be determined, the lease equipment account is usually credited with the full sales price amount. This method of accounting will normally not be disturbed as long as the lease equipment account balance exceeds the depreciation reserve balance. On those transfers where the cost can be ascertained, the lease equipment and reserve accounts are charged with the cost and depreciation figures, and the gain or loss is recognized. If the amounts are material and the tax cost can be ascertained, the agent should make sure that the gain or loss on the transfers is recognized.

4.41.1.3.9  (02-19-2008)
Oil and Gas Well Depletion

  1. An oil and/or gas producing property is a "wasting" asset. The quantity of oil and/or gas found in any natural deposit is finite. As the oil and/or gas is produced and removed from the deposit, the deposit is lessened or depleted. The owner of an economic interest in an oil and/or gas producing property may be entitled to a deduction from income for depletion of such economic interest as the oil and/or gas is produced and sold. Mineral interests, royalties, working interests, overriding royalties, net profits interests, and production payments are all economic interests in mineral deposits.

  2. Once a mineral property becomes productive, the owner or owners of economic interests in that property must recover their cost basis through the depletion deduction (or in the event of sale or other disposition prior to total depletion of the property as provided in the IRC for such sale or other disposition).

  3. IRC 611(a) provides, in the case of oil and gas wells, for a reasonable allowance for depletion as an allowable deduction in computing taxable income.

  4. The IRC provides two specific methods of computing the depletion deduction:

    • Cost depletion

    • Percentage depletion

  5. The cost depletion method is essentially a "unit of production" method of computing the allowable current tax period deduction. This computation is based on the taxpayer's basis as provided in IRC 612.

  6. The percentage depletion deduction is a specified percentage of the taxpayer's gross income from the property, but is limited to a maximum of 100 percent of the taxpayer's net taxable income from the property. This is generally termed the "100 percent of net income limitation" . The 100 percent of net taxable income is computed without allowance for depletion in IRC 613(a). Refer to IRM 4.41.1.3.9.1.4 for a full discussion.

  7. IRC 613A severely restricts the availability of percentage depletion for oil and gas production. In general, taxpayers classified as Independent Producers or Royalty Owners may claim percentage depletion on a limited volume of oil and gas production each year.

  8. If the percentage depletion is computed pursuant to IRC 613A(c), there is also a further limitation of 65 percent of the taxpayer's taxable income from all sources for the tax period in IRC 613A(d)(1). The method of computing the depletion deduction is not elective. The taxpayer must be allowed the deduction computation which allows the largest deduction. Allowable depletion, which is the higher of cost or percentage depletion, reduces the taxpayer's depletable basis (but not below zero) in the property.

  9. As this can involve a highly complex computation, an agent encountering a depletion problem should consult an engineer for assistance.

  10. The depletion computation is "off" book and the calculation of percentage depletion is solely for tax purposes. Corporate taxpayers should make a Schedule M-1 adjustment for excess percentage depletion over cost.

4.41.1.3.9.1  (07-31-2002)
Purpose and Statutory Authority for Depletion

  1. The purpose of the cost depletion computation and deduction is to allow the taxpayer a tax-free return on capital investment. The purpose of the percentage depletion deduction is to avoid the problems which were connected with the "discovery value" depletion deduction and provide incentives to investors and operators to undertake the very risky drilling and exploration operations necessary to find and produce oil and gas. "Discovery value" depletion will not be allowed. Refer to IRM 4.41.1.3.9.1 for a full discussion.

  2. Cost depletion deductions are authorized by IRC 611, IRC 612 and the regulations issued pursuant to these sections. Prior to January 1, 1975, percentage depletion was authorized by IRC 613 and the regulations issued pursuant to this section. Subsequent to January 1, 1975, percentage depletion authorized by IRC 613, for oil and hydrocarbon gas wells, is substantially limited by IRC 613A. Those limitations are discussed in IRM 4.41.1.3.9.3. IRC 613A provides that, except for certain conditions listed, percentage depletion is allowable under IRC 613.

4.41.1.3.9.1.1  (12-03-2013)
Economic Interest

  1. An economic interest in an oil and gas property is possessed in every case where a taxpayer has acquired, by investment, any interest in minerals in place and secures, by any form of legal relationship, income from the extraction of the oil and/or gas for which the taxpayers seeks a return on capital investment. Refer to Treas. Reg. 1.611–1(b).

  2. In many foreign countries, a corporation cannot acquire legal title to any of the lands, or to any petroleum or other hydrocarbons contained therein or produced therefrom. Rev. Rul. 73-470, 1973-2 CB 88 illustrates the rights and obligations that would permit a corporation to have an economic interest for purposes of depletion and intangible drilling costs with respect to United States federal income taxes.

  3. Depletion deductions are allowable only to the owner of an economic interest in the mineral deposit. Although a production payment is by definition an economic interest, IRC 636 provides that the payee will not be treated as the owner of an economic interest.

  4. The agent must distinguish between an economic interest and an economic advantage. The contractual right to purchase oil or gas after it has been produced is an economic advantage. See Rev. Rul. 68–330, 1968–1 CB 291. Court cases turning on the "economic interest" concept are Tidewater Oil Co. v. United States, 339 F.2d 633 (Ct. Cl. 1964); 14 AFTR 2d 6043; 65–1 USTC Para. 901A; CBN Corp. v. United States, 364 F.2d 393 (Ct. Cl. 1966); 18 AFTR 2d 5143; 66–2 USTC 86,703; cert. denied, 386 U.S. 981; Southwest Exploration Co. v. Commissioner , 350 U.S. 380 (1956); 48 AFTR 683; 56–1 U.S. 54,691; and Estate of Donnell v. Commissioner, 48 TC 552 (1967) AFF'D 417 F.2d 106 (5th Cir. 1969).

  5. The agent should be able to determine the "economic interest" status of an asset by obtaining from the taxpayer's property acquisition files or from any other sources the documents, letter agreements, assignments, unitization agreements, and operating agreements. The division order is the legal abstract of mineral interest in a specific property and indicates each party's percentage of ownership. These documents should be studied carefully for the nature of the interest owned by the taxpayer.

  6. The agent should not be concerned about the economic interest status unless the taxpayer has claimed depletion deductions or IDC deductions. These are the only types of deductions which are affected.

  7. If the taxpayer claims cost depletion deductions, the agent should be primarily concerned with basis, reserves of oil and/or gas, current tax period production, and the computation of the deduction.

4.41.1.3.9.1.2  (07-31-2002)
Definition of Depletable Income

  1. For income tax purposes for tax years ending prior to January 1,1975, the gross income from the property is the amount for which the taxpayer sold the oil or gas in the immediate vicinity of the well, and the total was subject to percentage depletion. However, IRC 613A eliminated percentage depletion for some taxpayers and limited the amount of production subject to percentage depletion for others.

  2. Thus, in some instances, the entire gross income from the property may not be subject to percentage depletion because of the limitations of IRC 613A.

  3. In computing percentage depletion, the gross income from the property must meet the provisions of IRC 613A(b), and IRC 613A(c). Refer to IRM 4.41.1.3.9.3, Percentage Depletion for full details.

4.41.1.3.9.1.3  (10-01-2005)
Gross Income from the Property

  1. For oil and gas wells, the IRC does not define gross income from the property. However, Treas. Reg. 1.613–3(a) still provides, "In the case of oil and gas wells, gross income from the property, as used in IRC 613(c)(1), means the amount for which the taxpayer sells the oil or gas in the immediate vicinity of the well. If the oil or gas is not sold on the premises but is manufactured or converted into a refined product prior to sale, or is transported from the premises prior to sale, the gross income from the property shall be assumed to be equivalent to the representative market or field price of the oil or gas before conversion or transportation." For court determinations of representative market or field price, see the following:

    • Shamrock Oil and Gas v. Commissioner, 35 T.C. 979 (1961)

    • Hugoton Production Co. v. United States, 315 F.2d 868 (Ct. Cl. 1963); 11 AFTR 2d 1198; 63–1 USTC 88,025

    • Panhandle Eastern Pipe Line Co. v. United States, 408 F.2d 690 (Ct. Cl. 1969); 23 AFTR 2d 69-933; 69–1 USTC 84,214

    • Exxon Corp. v. United States, 88 F.2d 968 (Ct. Cl. Fed Cir); 96–2 USTC 50,324; 77 AFTR 2d 2521; (Cert. denied)

    • Exxon Corp. v. Commissioner , 102 T.C. 721 (1994)

    • Exxon Mobil Corporation v. U.S., CA-FC, 2001-1 USTC 50,348, aff’g in part, rev’g in part, 2000-1 USTC 50,116, 45 FedCl 581, 244 F3d 1341

  2. Of prime importance in determining gross income from the property is the principle that only 100 percent of the proceeds of actual sales of oil and gas production in the immediate vicinity of the well or representative market or field price are subject to depletion.

  3. The deduction for depletion is to be equitably apportioned between the lessor and lessee. See Treas. Reg. 1.611–1(b)(2). The U.S. Supreme Court held in Helvering v. Twin Bell Oil Syndicate, 293 U.S. 312 (1934); XIV–1 C.B. 253; 14 AFTR 712; 35–1 USTC 386 that this meant the gross income on which percentage depletion is computed.

  4. When oil or gas is sold in the immediate vicinity of the well to an unrelated purchaser, there are relatively few problems. Gross income from the property includes any production or severance taxes which are the liability of the seller. These taxes are usually withheld by the purchaser (pipeline company) and paid to the state. If the purchaser of the oil or gas charges the seller a fee for gathering, transporting, and/or compressing the oil or gas, or if the seller performs these services, these costs are a decrease in gross income from the property and not lease operating expenses. Refer to Rev. Rul. 75–6, 1975–1 CB 178, for compression cost treatment and Panhandle Eastern Pipe Line Co. v. United States, 408 F.2d 690 (Ct. Cl. 1969); 23 AFTR 2d 69–933; 69–1 USTC 84, 214 for transportation cost treatment. The agent should analyze lease operating expense and "other" expenses to determine if these types of costs have been properly treated when paid to the pipeline purchaser. Analysis of depreciation accounts will indicate if pipelines or compressors are in use by the taxpayer. Gross income from the property can be verified as to source and type of income by studying and tabulating pipeline run statements and division orders. The contract between the purchaser and producer for sale of the oil or gas may have provisions which clearly indicate the portions of the purchase price which exceeds the field price of oil or gas in the immediate vicinity of the well.

  5. The working interest owner's gross income from the property must not include income from production which is paid to royalty owners and the other owners of economic interests in the property. Refer to Mesa Petroleum Co. v. Commissioner, 58 T.C. 374 (1972), and Treas. Reg. 1.613–2(c)(5)(i).

  6. When produced gas is not sold in the immediate vicinity of the well but is transported by the producer to a gasoline plant and processed for the extraction of liquid hydrocarbons, gross income from the property is deemed to be equivalent to the representative market or field price. However, there are instances in which there is no determinable representative market or field price. These situations have given rise to several court cases:

    • Weinert v. Commissioner , 294 F.2d 750 (5th Cir. 1961); 8 AFTR 2d 5417; 61–2 USTC 81,606

    • Mountain Fuel Supply Co. v. United States, 449 F.2d 816 (10th Cir. 1971); 28 AFTR 2d 71–5833; 71–2 USTC 87,650; cert. denied, 405 U.S. 989

    • Shamrock Oil and Gas v. Commissioner, 346 F.2d 377 (5th Cir. 1965).

  7. In the above instances, it is necessary to make a determination of gross income from the property by studying the data. If the depletion claimed for gas production is significant, the agent should request the assistance of an engineer.

  8. The percentage depletion deduction is based on a percent of the gross income from the property, which means the amount for which the taxpayer sells the oil or gas in the immediate vicinity of the well ( see Treas. Reg. 1.613–3(a)). If the sales price of the oil or gas is determined after transportation, compression, conversion, manufacturing, or similar activities, which are not production activities, the increase in the sales price attributable to those activities must be excluded from the price. Refer to Rev. Rul. 75–6, 1975–1 CB 178.

  9. Because the taxpayer is entitled to compute depletion on the gross income from the property, if the sales have occurred after one of the activities listed in paragraph (8) above, then a method must be devised to determine price in the immediate vicinity of the well. It should be emphasized it is a price determination not a value determination. The proportionate profits method applied in case of mines (Treas. Reg. 1.613–3(d)) has not been accepted by the courts for oil and gas.

  10. If a taxpayer has claimed percentage depletion on the sale of gas and the depreciation schedule shows the taxpayer also owns and operates a gasoline plant, the agent should analyze the source of income—plant sales or lease sales. If plant sales are allocated back to the leases, the agent should request engineering assistance.

4.41.1.3.9.1.4  (10-01-2005)
Net Taxable Income from the Property

  1. Percentage depletion is computed on a property-by-property basis. The agent should become familiar with the "property concept" before attempting to determine taxable income from the property. For definition of "the property," see IRC 614 and the regulations thereunder. Also, refer to IRM 4.41.1.3.9.3.2, Property Defined.

  2. Taxable income from the property is important because the percentage depletion deduction is generally limited to 100 percent of the taxable income from the property. Refer to IRC 613(a). Taxable income from the property is computed in accordance with Treas. Reg. 1.613-5. For tax years beginning after December 31, 1997, and before January 1, 2008, or beginning after December 31, 2008, and before January 1, 2012 the net income limitation is suspended for domestic oil and gas production from marginal properties. Refer to IRC 613A(c)(6)(D) and IRC 613A(c)(6)(H).

    Note:

    The suspension is not applicable for tax years beginning after December 31, 2007 and before January 1, 2009

    .

  3. Net taxable income from the property is gross income from the property as determined in IRM 4.41.1.3.9.1.4 reduced by the following:

    1. Operating Expenses—IRC 162. The agent should check invoices on the larger accounts to see that the expenditures are reported for the correct properties and in the correct reporting period.

    2. Losses—IRC 165

    3. Depreciation of Lease Equipment—IRC 167 and IRC 168. The depreciation claimed for tax deduction purposes should be deducted to reach taxable income. If depreciation is claimed for equipment which served more than one property, the deduction should be allocated among the properties on a reasonable basis.

    4. Overhead Attributable to the Property —The taxpayer who produces oil and gas will have deductible expenses such as officers' salaries, office utilities, building depreciation or rent, and general office expenses which are not attributable to any particular property. These expenses are termed indirect or overhead. Treas. Reg. 1.613–5(a) requires that these expenses be allocated between producing activities and other activities. They must be further allocated to the individual properties on a reasonable basis. Allocation based on gross income or direct expense is acceptable but the method used should be consistently followed. Generally, allocations of overhead among properties on the basis of direct expenses is preferred since overhead is likely to be associated with direct costs. If the taxpayer has not allocated overhead to lease operating costs, the agent should scan the depletion schedule. If no properties will be affected, or only a minimal adjustment appears likely, the agent should not pursue the overhead allocation. The agent need not make calculations to allocate to each property—only to the ones which will result in adjustment, but the agent must be able to show that the adjustment is appropriate.

    5. Intangible Drilling Costs—IDC should be deducted for purposes of the 100 percent limitation. Refer to Rev. Rul. 77–136, 1977–1 CB 167. The costs of a dry hole drilled on a lease, in an effort to penetrate and produce an already producing property, are expenses of that property. The agent may be able to determine the purpose of a well by asking the taxpayer for the AFE or its equivalent which authorized the drilling of the well. This may be in the well file or company financial records. Companies which publish annual reports may include comments concerning some specific wells. Applications to drill the well which are filed with the state agency having jurisdiction also probably will indicate the purpose. The IDC of wells drilled for the purpose of locating and producing another pay zone on a lease already producing are not costs of the existing property, unless the taxpayer does not elect separate property treatment. Refer to IRM 4.41.1.3.9.3.6, Separate Mineral Interest Election.

    6. Advalorem and other taxes (other than Federal income taxes) should also be allocated to the properties per IRC 164.

    7. Interest expense on money borrowed to purchase or develop the property was decided in St. Mary's Oil and Gas Co. v. Commissioner, 42 B.T.A. 270 (1940).

  4. For an example of the correct computation of "Gross Income from the Property" and "Net Taxable Income from the Property," see Rev. Rul. 79–73, CB 1979–1, 218 and Rev. Rul. 81–266, 1982–2 CB 139.

  5. On occasion, a taxpayer may overpay IDC in a tax year and be reimbursed in the following year. The taxpayer then shows the reimbursement in the "taxable income" computation as a negative IDC deduction. This has the effect of showing a higher than actual taxable income from the property. Negative IDC should be removed from the computation as its inclusion distorts the taxable income calculation. Scanning the IDC accounts should identify any negative entries.

  6. If a taxpayer owns a fraction of the working interest and operates the property for others, the taxpayer charges the others an "overhead" or operating fee. This charge is income from operating properties for others and not a reduction in operating costs. When a taxpayer operates properties for others, as well as for itself, the agent should study the taxpayer's accounting for the income to verify that it is not being used to increase net income from the property or to reduce allocable overhead expenses.

  7. Gain, under IRC 1245, is not an allowable increase in net income from the property in the case of oil and gas wells as it is in the case of mines. Refer to Treas. Reg. 1.613–5(b).

  8. A taxpayer may follow the practice of only showing the IDC costs of producing wells on a depletion computation schedule. Dry-hole costs or some producing well costs may be shown under "other deductions" dry-hole costs, or abandonment losses. The agent should obtain schedules and supporting documents for these accounts. Comparison of names on the various schedules may indicate a dry hole was drilled on a producing property and its cost not deducted to reach taxable income.

    Example:

    Taxpayer Smith's percentage depletion schedule for R. Licker Lease shows gross income of $200,000, net income of $80,000, with an allowable percentage depletion of $80,000. The schedule of dry-hole costs totaling $126,000 may include an R. Licker Well No. 7 at $38,500. Investigation may also reveal this well was drilled as an intended extension in the known deposit. The result is percentage depletion of $41,500 ($80,000–$38,500).

4.41.1.3.9.1.5  (10-01-2005)
Produced and Sold

  1. A depletion deduction is not allowable when the oil or gas is produced. The deduction is allowable when the produced mineral product is both produced and sold and income is reportable. Refer to Rev. Rul. 76–533, 1976–2 CB 189 and Treas. Reg. 1.611–2(a)(2).

  2. Oil or gas which is not sold but is transported from the property is depletable at its representative market or field price when used or consumed by the producer. See Rev. Rul. 67–303, 1967–2 CB 221, and Rev. Rul. 68–665, 1968–2 CB 280.

  3. The agent can determine the existence of depletion claimed on oil or gas which has not been sold by comparing the claimed gross income from the property for depletion computation purposes against the pipeline run statements and/or the gross income for income reporting purposes.

  4. Gas balancing agreements can have an effect on the reporting of gross income for taxpayers involved in a joint venture that elects out of the provisions of Subchapter K of the code. Refer to IRM 4.41.1.3.9.1.5.

4.41.1.3.9.1.6  (10-01-2005)
Representative Market or Field Price

  1. As indicated under gross income from the property in IRM 4.41.1.3.9.1.6, oil or gas not sold in the immediate vicinity of the well but transported, manufactured, or converted prior to sale is included in gross income from the property at the representative market or field price. The terms representative market or field price are not defined in the IRC or Regulations but have been defined by the six court cases cited in the IRM.

  2. The representative market or field price is a factual determination that may vary among producer-manufacturers.

  3. As defined by the court decisions, the representative market or field price is a weighted average price per MCF of gas. The weighted average takes into account all wellhead sales of gas, which is comparable to the gas of the producer-manufacturer in terms of quality, pressure, and location. The computation includes all wellhead sales during the tax period without regard to the date the sales agreement was contracted.

  4. The representative market or field price may be different for two producer-manufacturers within the same field for the same year.

  5. If, on review of the producer-manufacturer's schedules of gross income from the properties, it is found that certain amounts are periodically computed rather than entered from pipeline run statements, the agent may find that the taxpayer should be using the representative market or field price.

  6. The agent may find under expense of operation amounts paid for compression, transportation, or other nonproducing types of expenses which indicate oil or gas is not sold in the immediate vicinity of the well.

  7. Gas lease operating expenses are usually comparatively low. Large operating expenses for gas wells warrant close checking to discover the cause.

  8. If an agent encounters a representative market or a field price problem, an engineer should be consulted.

4.41.1.3.9.2  (10-01-2005)
Cost Depletion

  1. The cost depletion deduction method assures the owner of an oil or gas producing property that the allowable tax deduction is at least equal to the investment in the depleting property and tracks as rapidly as the asset is consumed.

  2. For computing cost depletion a "unit cost" must first be computed by dividing the taxpayer's adjusted basis by the number of remaining recoverable units of oil and/or gas. The taxpayer's adjusted basis is determined under IRC 1011. The number of remaining recoverable units for any tax period is the estimated number of recoverable units determined at the end of the tax period plus the number of units produced and sold during the tax period. The unit cost is then multiplied by the number of units sold during the tax period to compute the cost depletion deduction. Refer to Treas. Reg. 1.611-2(a).

  3. In certain situations cost depletion can also be based on dollar amounts. For lease bonuses and advanced royalties see Treas. Reg. 1.612-3(a). In this calculation, the taxpayer's remaining basis is divided by the total remaining gross income expected to be received from the beginning of the tax period to total depletion of the property to calculate a unit cost in dollars cost per expected dollar receipts. The resulting fraction is then multiplied by the tax period's reportable gross income to compute the allowable cost depletion. Refer to Treas. Reg. 1.612–3(a).

  4. If a taxpayer receives a lease bonus on wildcat acreage and claims cost depletion equal to 100 percent of cost, this has the effect of claiming the minerals are worthless as they supposedly will produce no future income. Worthlessness must be proven by an event, and no such event has occurred. Further, it is assumed that the lease itself has value or the lessee would not have paid the bonus. Therefore, cost depletion should not be allowed unless it is possible to make a reasonable estimate of future income and that estimated income is not zero. However, for a contrary decision, see Collums v. United States, 480 F. Supp. 864 AFTR 2d 80–751 (DC Wyo. 1979) with respect to which no action on decision has been issued. Refer to PLR 8532011 and IRM 4.41.1.3.9.4 for additional details on lease bonuses.

  5. For estimates of recoverable units, see IRM 4.41.1.3.9.2.2, Reserves of Oil and Gas.

  6. In large cases with numerous calculations, a taxpayer's calculations can be quickly verified through a Computer Audit Specialist.

  7. Cost depletion, if it is greater than the allowable percentage depletion, must be allowed in lieu of, but not in addition to, percentage depletion.

4.41.1.3.9.2.1  (12-03-2013)
Depletable Basis

  1. As provided in IRC 612, generally a taxpayer's basis for the cost depletion computation is the adjusted basis under IRC 1011.

  2. When a taxpayer purchases an interest in a property and there is only one asset, few cost problems arise.

  3. Frequently, a problem of basis for cost depletion arises when a taxpayer purchases more than one asset for a lump sum. When a taxpayer purchases a producing lease and related equipment for a lump sum, the allocation of cost between leasehold (depletable) and equipment (depreciable) is controlled by Treas. Reg. 1.611–1(d)(4), Treas. Reg. 1.167(a)–5, and Rev. Rul. 69–539, 1969–2 CB 141. The cost is allocated between leasehold and equipment based on relative fair market values. However, Treas. Reg. 1.1245–1(a)(5) provide that on the sale of IRC 1245 property and non-IRC 1245 property, if the buyer and seller are adverse as to the allocation, any arm's-length agreement between the buyer and seller will establish the allocation. In the absence of such an agreement, the allocation is made by considering the appropriate facts and circumstances.

  4. Allocation of purchase price may involve a potential whipsaw (aka correlative adjustments) situation. Refer to IRM 4.10.7.4.9http://irm.web.irs.gov/Part4/Chapter10/Section7/IRM4.10.7.asp#4.10.7.4.9. When a material amount of tax is involved, secure the returns of both sides to the transaction to ensure consistency in the treatment of the transaction.

  5. Allocation of a lump-sum purchase price between leasehold and equipment is usually an engineering problem. The agent should secure the following before requesting engineering services:

    • copies of the contracts and purchase agreements

    • taxpayer's allocation method

    • workpapers for making the allocation

    • copy of the taxpayer's engineering report which was used as a guide in purchasing the assets

  6. Allowable depletion deductions reduce the taxpayer's remaining basis for cost depletion computations. Accounts should be maintained so that all capitalized cost and all allowable depletion is accumulated. If costs exceed the depletion reserve (accumulated depletion), the difference is the "remaining basis." The effect of this is that an addition to capital of any asset may be fully offset by previously allowed percentage depletion so that, immediately after a substantial capitalization, the taxpayer's "remaining basis" may be zero. See Rev. Rul. Rev. Rul. 75–451, 1975–2 CB 330, and Treas. Reg. 1.614–6(a)(3), Example 1.

  7. Costs which should be capitalized include:

    • purchase price or bonus

    • attorney fees

    • abstract fees

    • commissions or other fees paid in connection with acquisition of the property

    • IDC

    • equipment costs paid in excess of the percentage applicable to the interest owned by the taxpayer; refer to Treas. Reg. 1.612–4(a)(3).

  8. Other costs that may affect basis are:

    • IDC which the taxpayer has not elected to expense under IRC 263(c)

    • delay rentals

    • equipment costs which are required to be capitalized under Rev. Rul. 69–332, 1969–1 CB 87

    • favorable geological and geophysical costs for properties outside the U.S.; refer to Rev. Rul. 77-188, 1977-1 CB 76 and Rev. Rul. 83-105, 1983-2 CB 51, and IRM 4.41.1.2.2.3.2.

4.41.1.3.9.2.2  (12-03-2013)
Reserves of Oil and Gas

  1. "Reserves" as of any date means the number of units currently and expected to be recovered subsequent to that date.

  2. In the computation of cost depletion, the "unit" " to be used is the principal unit or units paid for in the products sold. See Treas. Reg. 1.611–2(a). The unit for oil is barrels and for natural gas it is thousands of cubic feet (MCF). The IRS has traditionally allowed taxpayers to use the unit of the predominate product produced from each property or the "barrels of oil equivalent" which can be obtained by converting MCF’s of gas to equivalent barrels by dividing by a conversion factor of approximately 6 MCF per barrel.

  3. The estimates of reserves of oil or gas must be made "according to the method current in the industry and in light of the most accurate and reliable information obtainable" . Refer to Treas. Reg. 1.611–2(c)(1). The estimate (quantity)includes "developed" or "assured" and "probable and prospective" deposits. Industry definitions of proved reserves (proved developed and proved undeveloped) refer to minerals that are reasonably known, or on good evidence believed to exist when the estimates are made according to the method current in the industry and in the light of the most accurate and reliable information obtainable. All proved categories correspond to reserves described in Treas. Reg 1.611-2(c)(1) and should be included in the recoverable units for computation of cost depletion deduction. The examiner should closely review the taxpayer's reserves estimation, in light of operations or development work prior to the close of the taxable year, and include additional reserves required by applicable regulation to be consistent with industry standards and supported by taxpayer's actual practices. See IRS Coordinated Issue Paper, Cost Depletion Recoverable Reserves http://www.irs.gov/Businesses/Coordinated-Issue-Papers---LB&I.

  4. Effective for tax years ending on or after March 8, 2004 taxpayers may elect to use a "safe harbor" to calculate their total recoverable units. Total recoverable units are generally set equal to 105 percent of proved reserves (both developed and undeveloped) as defined by the 17 CFR of Regulation S-X (refer to IRC IRC 210.4-10(a) of Regulation S-X. The safe harbor must be used for all domestic oil and gas properties owned by the taxpayer. See Rev. Proc. 2004-19 and the Field Directive on Cost Depletion – Determination of Recoverable Reserves http://www.irs.gov/Businesses/Field-Directive-on-Cost-Depletion---Determination-of-Recoverable-Reserves.

  5. The "reserves" to be used in the cost depletion computations for any tax period are the "reserves" at the end of that tax period plus the units produced during that tax period. See Treas. Reg. 1.611–2(a)(3). This determination is important because the formula to compute cost depletion is generally the same as the one used to compute "depreciation, depletion, and amortization" (DD&A) for financial accounting. However, the amounts inserted into the various portions of the calculation are different. Care should be taken to assure that adjusting entries are being made to book amounts before tax cost depletion is calculated.

       
    CD= CP x [ATB/(CP+FP)]
       
    Where:  
    ATB = Amount of depletable tax basis remaining
    CD = Cost Depletion
    CP = Current Production
    FP = Future Production as of end of year
       

  6. IRC 611(a) provides for situations in which revision of estimates impacts the calculation of depletion allowance. For purposes of cost depletion, the taxpayer is not permitted to revise the reserve estimate based solely on economic factors, without operations or development work indicating the physical existence of materially different quantity of reserves than originally estimated to purchase or to develop the property. See Martin Marietta Corp. v. United States, 7 Cl. Ct. 586, 85–1 USTC 9284 (Cl. Ct. 1985) and http://www.irs.gov/Businesses/Coordinated-Issue-Petroleum-Industry-Cost-Depletion---Recoverable-Reserves-(Effective-Date:--January-13,-1997).

  7. The units to be used in the calculation of cost depletion deduction of any taxpayer are only the units which have been and will be produced to the interest owned by that taxpayer.

    Example:

    Taxpayer A owns a royalty of 1/8 of production in Lease Z. Lease Z has produced 8,000 barrels of oil during the current tax period. At the end of the tax period Lease Z contains 80,000 barrels of oil reserves. Taxpayer A's units produced during the current tax period are 1/8 of 8,000 barrels or 1,000 barrels. Taxpayer A's reserves of oil for cost depletion computation are 11,000 which is 1/8 of 80,000 barrels plus 1,000 barrels.

  8. Making estimates of the reserves of oil or gas is an engineering project. In most cases when cost depletion deductions are significant, the taxpayer will have "in-house" engineers or outside consultants prepare the estimates of reserves for use by the accounting department. These estimates may be used for full cost accounting financial statements and/or tax computations. It is important to understand that the circumstances under which a reserves estimate may be changed for tax purposes are different from circumstances under which reserves can be changed for financial reporting purposes. The agent should obtain copies of these estimates and forward them to the engineer. Engineers should refer to IRM 4.41.1.3.9.2.3, Appropriate Additional Reserves of Oil and Gas.

  9. If a taxpayer's cost depletion approaches or exceeds 50 percent of the net taxable income from the property or the cost per barrel of oil produced appears excessive, the agent should investigate the facts concerning the acquisition of the property and the basis in the property. There may be errors in the allocation of cost, estimation of reserves, or basis claimed. Units claimed to be produced for depletion purposes may be in excess of those reported for income reporting purposes. Sometimes assets transferred between subsidiaries may have been transferred at "book" rather than tax basis. Assets transferred between subsidiaries may have been transferred at tax cost, but the related reserve accounts may not have been transferred. IDC which were expensed for tax purposes may have been capitalized for "book" and cost depletion purposes. In years that percentage depletion exceeded cost depletion the excess percentage depletion may not have been deducted from cost basis.

4.41.1.3.9.2.3  (12-03-2013)
Appropriate Additional Reserves of Oil and Gas

  1. Disputes with taxpayers often arise in determining the quantity of "probable" or "prospective" reserves to be included in a property’s total recoverable units from oil and gas wells for purposes of computing cost depletion under IRC 611.

  2. Under Treas. Reg. 1.611-2, if it is necessary to estimate or determine with respect to any mineral deposit as of any specific date the total recoverable units of mineral products reasonably known, or on good evidence believed, to have existed in place as of that date, the estimate or determination must be made according to the method current in the industry and in the light of the most accurate and reliable information obtainable. The estimate of the recoverable units of the mineral products in the deposit for the purposes of valuation and depletion should include as to both quantity and grade:

    • The ores and minerals "in sight" , "blocked out" , "developed" , or" assured " , in the usual or conventional meaning of these terms with respect to the type of the deposits, and

    • "Probable" or "prospective" ores or minerals (in the corresponding sense), that is, ores or minerals that are believed to exist on the basis of good evidence although not actually known to occur on the basis of existing development. Such "probable" or "prospective" ores or minerals may be estimated: as to quantity, only in case they are extensions of known deposits or are new bodies or masses whose existence is indicated by geological surveys or other evidence to a high degree of probability; and as to grade, only in accordance with the best indications available as to richness.

  3. The minerals primarily produced in the petroleum industry are liquid and gaseous hydrocarbons. These are commonly referred to as oil, gas, and natural gas liquids. Some byproducts such as carbon dioxide and sulfur are also produced. Recoverable units or reserves volumes for hydrocarbons are usually reported as barrels (BBL) for liquids and thousands of cubic feet (MCF) for gases by domestic companies. Reserves may also be recorded in terms of barrel of oil equivalents (BOE) where the gas has been converted to an equivalent liquid volume (based on Btu content) and added to the oil reserves. International companies may use other units of measure for reserves in foreign locations. Examiners/engineers need to be aware that there are variations in reserve volume nomenclature, that standard conditions of volume measurement vary somewhat, and that conversion of gas volume to oil volume may be a source of error in determining hydrocarbon reserves.

  4. IRS examiners/engineers must follow the Coordinated Issue Paperhttp://www.irs.gov/Businesses/Coordinated-Issue-Petroleum-Industry-Cost-Depletion---Recoverable-Reserves-(Effective-Date:--January-13,-1997). According to the Coordinated Issue Paper, the taxpayer must include all proved reserves (both developed and undeveloped) in the cost depletion calculation. In addition, the taxpayer must include "appropriate additional reserves" which are generally referred to as probable reserves. The Coordinated Issue Paper also restates long-standing IRS policy that reserves estimates may not be revised solely because of changes in economic conditions.

  5. To minimize disputes over probable reserves, the IRS promulgated a safe harbor that taxpayers can elect for tax years ending on or after March 8, 2004. Refer to Rev. Proc. 2004-19, 2004-1 CB 563 and IRM 4.41.1.3.9.2.2.

4.41.1.3.9.2.3.1  (12-03-2013)
Problems in Determining Recoverable Reserves

  1. Determining the correct quantity of recoverable units for cost depletion can be a challenging task. Examiners will likely find each taxpayer to have unique business records and practices related to the estimation and compilation of oil and gas reserves. In addition taxpayers may use terms that have a specific meaning to them, but different meanings to others. Examples include:

    • Reserves, recoverable units, expected ultimate recovery

    • Probable, prospective, possible, potential

    • Non-producing, undeveloped, noncommercial, static

    • Likelihood, reasonable certainty, confidence, probability

  2. Taxpayers estimate, compile, utilize, and report reserves in different ways for different purposes. Taxpayers may have reserve estimates for internal purposes different from those reported to the IRS. Taxpayers may consider "static reserves" to be reserves that are proved in the technical sense, but not commercially recoverable due to economic or political reasons.

  3. For the same occurrence (or anticipated occurrence) of oil and gas, taxpayers may determine different quantities associated with different categories. For example, the quantity of "unrisked" probable reserves may be higher than the "most likely" probable reserves.

  4. Taxpayers may estimate proved reserves down to the property level, but unproved reserves only down to the field level. Taxpayers may also have estimates of unproved reserves that are not in a ledger format, but instead are contained in analyses of specific property acquisitions.

  5. Examiners are likely to find that no "appropriate additional reserves" have been incorporated by the taxpayer in its cost depletion computation.

  6. Publicly traded oil companies must annually submit an estimate of their proved reserves (both developed and undeveloped) to the Securities and Exchange Commission (SEC) http://www.sec.gov/. Many taxpayers use these same reserves for cost depletion. However, some taxpayers exclude subcategories such as proved undeveloped reserves or proved non-producing reserves. SEC reserves can be very susceptible to negative changes in economic conditions, and may be less than the true proved reserves for particular properties. The SEC's reserves definitions and reporting guidelines for oil and gas activities are contained in Reg. section 210.4-10 of Regulation S-X of the Securities Exchange Act of 1934. http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&sid=20c66c74f60c4bb8392bcf9ad6fccea3&rgn=div5&view=text&node=17:2.0.1.1.8&idno=17#17:2.0.1.1.8.0.21.42

  7. The SEC’s definitions of reserves and reporting guidelines were essentially unchanged from 1978 to 2009. A major effort to modernize those items occurred in the late 2000s, and submissions to the SEC after December 31, 2009 must comport with the revised SEC regulation. The older definition of proved reserves is not available online, therefore it has been memorialized in Exhibit 4.41.1-45. For convenience a portion of the current SEC reserves definitions is provided in Exhibit 4.41.1-46. The major differences are summarized as follows:

    • Definition of "current prices" (for determining if the reserves are economic) is now based on 12-month historical average instead of the last day of the year. Industry considered the latter to be unreliable because it was suspect to aberrations in the daily price of oil and natural gas.

    • Nontraditional resources (such as "oil sands" and "oil shale" that are mined) are now considered oil and gas activities.

    • The "certainty level" needed to classify reserves can be based on modern technologies, instead of only certain specified technologies.

    • For estimates of proved undeveloped reserves, the certainty criterion has been replaced by "reasonable certainty" .

    • Companies have the option to disclose probable and possible reserves, and definitions of those terms are provided.

  8. The Service’s engineers have concluded that the impact of the SEC’s revisions on the cost depletion issue from a risk analysis standpoint is minor. For example, at present very few public companies have chosen to disclose probable and possible reserves. Further, even though "current prices" are now assumed equal to the prior 12-month average instead of the last day of the reporting year, some companies have announced write-downs of reserves due to declining natural gas prices in the U.S.

  9. Companies are also required by law to annually report to the Energy Information Administration (EIA) an estimate of proved reserves in the U.S. http://www.eia.gov/survey/form/eia_23s/instructions.pdf. Examiners should be aware of the peculiarities of this data -

    • Each company reports reserves for only those properties that it operates

    • The reserves are reported by field, not by specific lease or property

    • The reserves are reported on an 8/8 basis; therefore they are not net to the company's ownership interest.

    The EIA treats this information as proprietary, so examiners would have to obtain this information from the taxpayer. The EIA's definition of proved reserves is very similar to that of the Society of Petroleum Engineers (SPE). http://www.eia.doe.gov/pub/oil_gas/natural_gas/survey_forms/eia23li.PDF

  10. The Society of Petroleum Engineers (SPE) is the preeminent industry organization for defining petroleum resources and reserves. For many years the SPE has worked with industry participants and other associations to promulgate both reserves definitions and other guidelines for the use of reserves preparers or reserves auditors. Its most recent efforts resulted in the publication of the Petroleum Resources Management System (PRMS) in 2007. To a large degree the current SEC’s definitions generally agree with the SPE’s definitions. The SPE Oil and Gas Reserves Committee recently issued Guidelines for Application of the Petroleum Resources Management System (PRMS) http://www.spe.org/industry/reserves.php, November 2011. This document replaces the 2001 guidelines and expands content to focus on using the 2007 PRMS to classify petroleum reserves and resources.

  11. To promote consistency of examinations, examiners and engineers should become familiar with the items mentioned above which are available at http://www.spe.org/industry/reserves.php.

  12. The SPE definitions and classifications have been drafted in great detail. The key concepts can be seen by the following excerpts:

    • Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.

    • Proved Reserves. An incremental category of estimated recoverable volumes associated with a defined degree of uncertainty. Proved Reserves are those quantities of petroleum which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. Often referred to as 1P, also as "Proven" .

    • Probable Reserves. An incremental category of estimated recoverable volumes associated with a defined degree of uncertainty. Probable Reserves are those additional Reserves that are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50 percent probability that the actual quantities recovered will equal or exceed the 2P estimate.

    • Possible Reserves. An incremental category of estimated recoverable volumes associated with a defined degree of uncertainty. Possible Reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10 percent probability that the actual quantities recovered will equal or exceed the 3P estimate.

    • Uncertainty in resource estimates is best communicated by reporting a range of potential results. However, if it is required to report a single representative result, the "best estimate" is considered the most realistic assessment of recoverable quantities. It is generally considered to represent the sum of Proved and Probable estimates (2P) when using the deterministic scenario or the probabilistic assessment methods. It should be noted that under the deterministic incremental (risk-based) approach, discrete estimates are made for each category, and they should not be aggregated without due consideration of their associated risk. See SPE 2001 Supplemental Guidelines, Chapter 2.5.

  13. The Society of Petroleum Evaluation Engineers (SPEE) is also a good source of information on estimating oil and gas reserves at www.spee.org.

  14. IRS petroleum engineers have concluded that as a factual matter:

    • The SPE's definition of proved reserves refers to minerals described in Treas. Reg. 1.611-2(c)(1) in that they are "reasonably known, or on good evidence believed to exist." SPE proved reserves (both developed and undeveloped) should be included in the cost depletion calculation.

    • The SPE's definition of probable reserves is generally consistent with minerals described in Treas. Reg. 1.611-2(c)(1)(ii). They are reasonably analogous to "probable and prospective" ores or minerals. SPE probable reserves should be included at the appropriate time in the cost depletion calculation as discussed further in the Analysis of SPE Factual Scenarios of Probable Reserves that follows.

    • The SPE's definition of possible reserves is generally not consistent with minerals described in Treas. Reg. 1.611-2(c)(1). Their low level of confidence is not consistent with minerals that are "reasonably known, or on good evidence believed to exist" or those that are "probable and prospective" . Generally, SPE possible reserves should not be included in the cost depletion calculation.

4.41.1.3.9.2.3.2  (12-03-2013)
Analysis of SPE Factual Scenarios of Probable Reserves

  1. The SPE's website for reserves definitions formerly included a description of several factual scenarios for probable reserves. IRS petroleum engineers analyzed each factual scenario and determined -

    • Whether the described scenario meets the criteria of Treas. Reg. 1.611-2(c)(1);

    • What quantity of probable reserves should be included in the cost depletion calculation; and

    • When the probable reserves should be included in the cost depletion calculation

    Even though the SPE no longer includes these factual scenarios in its discussion of reserves, they are universal in nature and provide a good reference point for examiners/engineers. In this analysis, the terms reserves, proved reserves, and probable reserves carry the same meaning as the SPE's former definition of these terms. Examiners/engineers should be cognizant that any particular taxpayer's definition of these terms may differ from the SPE's. The complete analysis is contained in Exhibit 4.41.1-26.


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