The cost depletion deduction is the method used to assure the owner of an oil or gas producing property that he/she will be allowed a tax deduction at least equal to his/her investment in the depleting property as rapidly as the asset is consumed.

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 section 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. See Treas. Reg. 1.611-2(a).

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. See Treas. Reg. 1.612–3(a).

If a taxpayer receives a lease bonus on wildcat acreage and claims cost depletion equal to 100 percent of his/her 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. See PLR 8532011 and IRM 4.41.1.3.7.4 for additional details on lease bonuses.

For estimates of recoverable units, see IRM 4.41.1.3.7.2.2, Reserves of Oil and Gas.

In large cases with numerous calculations, a taxpayer's calculations can be quickly verified by use of a computer audit specialist.

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

The percentage depletion deduction is computed as a percent of gross income from the property, limited to the net taxable income from the property. For this reason, the definition of gross income from the property is very important. See IRM 4.41.1.3.5.1.3.

Percentage depletion is allowed under IRC section 613, but with the passage of the Tax Reduction Act of 1975 (effective January 1,1975, and applicable to years ending after December 31,1974), percentage depletion is restricted for oil and/or hydrocarbon gas as provided in IRC section 613A. IRC section 613A is quite complex and restrictive and should be studied carefully by the agent. The Basic and Advanced Oil and Gas Textbooks (Texts 3185–03 and 3186–04) provide a good discussion of IRC section 613A. Refiners and retailers (as defined in IRC section 613A(d)(2)) are not allowed percentage depletion on oil or hydrocarbon gas, except as provided in IRC section 613A(b).

Bonus is the term applied to the considerations received by the lessor upon the granting or execution of an oil and gas lease or sublease. It may be paid in a lump sum or in installments.

To the payor (lessee), the bonus payment is a capital investment made for the acquisition of an economic interest in the minerals (working interest). A production payment retained by the lessor is treated as a bonus payable in installments. See Treas. Reg. 1.636–2(a). The lessee's investment in the working interest is recoverable through deductions for depletion (if the lease becomes productive), abandonment loss (if the working interest becomes worthless or expires), or as cost of sale (if the working interest is sold).

To the payee (lessor), the bonus payment is ordinary income subject to cost depletion. See Treas. Reg. 1.612–3(a). Percentage depletion is not allowed on lease bonus payments. See IRC section 613A(d)(5).

As explained in IRM 4.41.1.3.7.2, the cost depletion formula in Treas. Reg. 1.612–3(a) does not produce a realistic result with respect to a nonproven property. However, in Collums V United States , 480F. Supp. 864, 51, the Court allowed a sublessor to use the computation to deduct 100 percent of his basis in a nonproven property as cost depletion. No action or decision has been issued with respect to this case. The case should not be followed unless it becomes apparent that the result in Collums will be accepted by the Service. Such is not the case at this time. See PLR 8532011.

Oil and gas properties are frequently owned by a partnership, trust, or estate. The depletion deduction, allowed by IRC sections 613 and 613A, on oil and gas production is subject to special rules when mineral properties are held by a partnership, trust, or estate. The examiner must be aware of the special rules to ensure that beneficiaries and partners are not allowed to benefit by circumventing the limitations in the law.

The partnership is a favorite vehicle for conducting oil operations because of the practice and need to share the inherent risk of drilling for and producing oil and gas. Also, the partnership form is utilized widely to finance oil and gas operations that may be far too costly for one individual or company. However, IRC section 703(a)(2)(F) states that the depletion deduction is not allowed at the partnership level. Depletion must be computed at the individual partner's level and is subject to the special limitations in IRC section 613A. Cost depletion and/or percentage depletion will be allowable under IRC sections 611, 612, 613, and 613A as stated above but only at the partner's level. Preparers sometimes deduct depletion on Form 1065 (Partnership Income Tax Return) because some or all of the partners are limited under IRC section 613A, which would deny or limit the allowance of depletion to the partners. By deducting the depletion on the partnership return, it would merely decrease the net income distributed by the partnership, thus, circumventing the limitations under IRC section 613A.

Each partner must keep track of his/her adjusted basis in the partnership oil and gas properties to enable him/her to compute cost depletion and tax preference depletion. The partner's basis on the partnership books will usually be reduced by his/her allocable share of depletion although the partner may have been limited under IRC section 613A and be unable to deduct depletion. Therefore, it is likely that the partner's actual basis in the partnership will differ from the basis shown on Form 1065 because of the depletion deduction and other reasons. Copies of the Schedules K, prepared for the members of a partnership, should be inspected to ensure that the depletion deduction has not been deducted at the partnership level and also allocated to certain partners to create a double deduction. In the case of limited partnerships, the partnership may borrow funds from a lending institution for the purpose of exploring or developing mineral property. Any increase in a partner's share of partnership liabilities is treated as a contribution of money that increases basis in his partnership interest. See IRC sections 752(a) and 722.

Trusts and estates are also subject to special rules in computing depletion. The administrator or trustee should make the initial election on the Form 1041 (Fiduciary Income Tax Return) as to whether cost or percentage depletion is claimed. The law was changed with the 1975 Tax Reform Act. Prior law will not be discussed here because of limited application. Percentage depletion for a trust or estate is subject to the limitations in IRC section 613A.

If the administrator or trustee allocates net income to the beneficiaries, they will be considered to have received their pro-rata share of the depletion. The depletion would again be subject to the limitations of IRC section 613A(c) and (d) at the beneficiaries level. Treas. Reg. 1.613A–3(f) explains the distribution of oil income and depletion out of a trust. The beneficiary is entitled to claim cost depletion, in any event, if cost exceeds his/her share of percentage depletion.

Examiners should examine or carefully inspect the Form 1041 to ensure that distributions to the beneficiaries is correct and correspond with the amounts reflected on the beneficiaries' returns. It is common practice for a trust instrument to provide for a reserve for depletion. Frequently, in such cases you will find that a trust or estate has claimed depletion upon 100 percent of the oil and gas produced and that the beneficiary has also claimed depletion upon his/her share of oil or gas income. The double deduction of depletion should, of course, be corrected. Refer to Treas. Reg. 1.613A–3(f) for guidance.

Frequently, it is necessary to determine the fair market value of oil and gas properties. Taxpayers may receive producing oil and gas properties as a result of taxable events such as corporate liquidations, exchanges of properties not qualifying for IRC section 1031 treatment, property received for services under IRC section 83, or in an outright purchase or sale. In each of these events, the consideration received is measured by the fair market value of the property.

For income tax purposes, the basis of property in the hands of a person acquiring the property from a decedent generally is the property's fair market value at date of death or "alternate date" under IRC section 2032, if elected. See IRC section 1014.

Fair market value determinations must also be made in respect to charitable contributions of property under IRC section 170(a).

The courts have considered the definition of fair market value many times. The Supreme Court in Montrose Cemetary Co. v. Commissioner , 309 U.S. 622 (1940); 23 AFTR 1071; 40–1 USTC 157, stated, "the fair market value is a price at which a willing seller and a willing buyer will trade, both having a reasonable knowledge of the facts ..." Treas. Reg. 1.170–1(c)(a) and 20.2031–1(b) define fair market value as ". . . the price at which the property would change hands between a willing buyer and a willing seller, neither being under any compulsion to buy or sell and both having reasonable knowledge of the facts." A similar definition of fair market value is found in Treas. Reg. 1.611–1(d)(2).

Treas. Reg. 1.611–2(d) provides for the priorities of methods to be used in determining the fair market value of mineral property. Treas. Reg. 1.611–2(d)(2) provides that an analytical appraisal (present value method) will not be used in either one of the following situations:

Treas. Reg. 1.611–2(e)(4) provides "the value of each mineral deposit is measured by the expected gross income (the number of units of mineral recoverable in marketable form multiplied by the estimated price per unit) less the estimated operating cost, reduced to a present value as of the date for which the valuation is made at the rate of interest commensurate with the risk for the operating life, and further reduced by the value of the improvements and of capital additions, if any, necessary to realize the profits." In practice, this method requires that:

A valuation of an oil and/or gas property is an engineering issue and, if the tax consequences warrant, should be referred for engineering services.

The agent should obtain, if possible, the data indicated in Treas. Reg. 1.611–2(g).

The physical characteristics of hydrocarbons and the reservoirs in which they are found are such that, other factors being equal, the higher the pressure in the reservoir the greater will be the ultimate recovery of hydrocarbons. This is true in the first month of production through the last month of production. Ultimate recovery is not necessarily directly proportionate to pressures. However, for every reservoir which produces oil and gas, there is a critical pressure called the "bubble point." The bubble point, sometimes called saturation pressure, is the pressure at which gas in solution with the oil is released and becomes "free gas." When the pressure in the reservoir drops below the bubble point, the gas automatically becomes free and moves more freely through the reservoir. This allows the gas to bypass the oil and leaves it dead in the reservoir. When this happens, much more of the oil clings to the reservoir rock with consequent loss of possible oil recovery. Because of this, good operators use every reasonable means to maintain relatively high pressure in the reservoir throughout its productive life.

One method used by operators to maintain reservoir pressures at optimum levels is by the injection of gas. Dry gas can be injected in the gas cap or as "dispersed gas injection." The dry gas injected in the gas cap in the past has served a dual purpose. It provided a place of storage for gas for which there was no profitable market, and it retarded the decline in reservoir pressure. Dispersed gas injection maintains pressure in the reservoir and pushes additional oil to the producing well bores.

Another method of tertiary recovery of oil is known as "enriched gas drive" or "miscible displacement." Under this method, a "slug" of liquefied petroleum gas is injected in the reservoir. This is followed by injection of gas or water. The desired effect is that the liquefied gas is miscible with the oil, will wash it from the rocks, and push it to the producing well bores.

The tax treatment of injected gas has been the subject of Rev. Ruls. 68–665, 1968–2 C.B. 280, 70–354, 1970–2 C.B. 50; and 73–469, 1973–2 C.B. 84.

Rev. Rul. 68–665, 1968–2 C.B. 280, allows depletion on produced dry gas used to fire boilers in a gasoline absorption plant, but the dry gas reinjected into the producing formation is not sold, does not contribute any value to the products sold, and is not subject to an allowance for depletion.

Rev. Rul. 70–354, 1970–2 C.B. 50, holds that, where a taxpayer can show that a portion of the injected gas cannot be expected to be recovered with subsequent production, the costs of the unrecoverable portion are deductible under IRC section 165(a) in the year of injection (or in the subsequent year in which it can be shown that such loss has been sustained). " Economic losses" are not allowable. Costs not recoverable under IRC section 165(a) are not deductible under IRC section 162 but are offset against the proceeds of the purchased gas when it is produced and sold in subsequent producing activities. When purchased and injected gas is subsequently produced and sold, the gain (or loss) is ordinary and not subject to depletion.

Rev. Rul. 73–469, 1973–2 C.B. 84, prospectively revokes a portion of Rev. Rul. 70–354, 1970–2 C.B. 50, with respect to that portion of the injected gas that will not be recovered. Subsequent to November 5,1973, costs of injected gas which will not be recovered but will benefit the reservoir by its presence in the reservoir over the life of the project, are capital expenditures. These costs are recoverable through depreciation.

The agent should be alert when examining lease operating expenses for evidence of expense deductions resulting from purchased gas. Actual deduction may not be listed under gas injected. It could be found under salt water disposal or other similar names. Any account which totals an unusually high amount should be carefully checked against original invoices on a month-by-month basis. The agent could discuss with the production people any gas injection programs. Ask about the cost of injected gas. Ask about earlier gas injection programs. It may be that gas purchased and expensed in earlier years is currently being produced, sold, and percentage depletion claimed on the proceeds. If the property is being produced under some form of unitization agreement, this agreement may contain definite provisions for differentiating between produced previously injected gas and native gas for royalty computation purposes. If a substantial problem arises, engineering services should be requested. The engineer may have special detailed knowledge of the project.

Percentage depletion is allowed without restriction for production from a domestic geothermal deposit. The statutory rate is 15%. The restrictions of section 613A, except for the denial of percentage depletion on lease bonuses, do not apply. See IRC section 613(e).

A geothermal deposit means a geothermal reservoir consisting of natural heat which is stored in rocks or in an aqueous liquid or vapor (whether or not under pressure).

Gross income is to be computed in the same manner as for oil and gas wells. See Rev. Rul. 85-10, 1985-1 CB 180. Technical Advice Memorandum 200308001 addressed a situation where it was impossible to determine a representative market or field price.

When a lease is sold or exchanged, a gain or loss is realized based on the difference between the selling price and the adjusted basis of the property sold.

The adjusted basis of the leasehold is determined by taking the original cost of the property, increasing it for capital additions, and reducing it by depletion allowed or allowable. Any writeoffs for abandonments, transfers, partial sales, etc., will also decrease the adjusted basis.

Additions to the basis should include costs such as bonuses paid for the lease, attorney fees, and other expenses incurred in connection with the acquisition, expenditures for geological opinions, surveys, geophysical work, and maps in connection with the acquisition or development of a lease. However, geophysical work conducted for a single well location is IDC. The taxpayer may also elect to capitalize intangible drilling and development costs, although capitalization is very rare.

The basis of the leasehold is reduced by any cost or percentage depletion allowed or allowable. The basis of depreciable equipment is reduced by any depreciation allowed or allowable. In both cases, any abandonment losses deducted, etc., would reduce the adjusted basis. However, partial abandonment losses are not allowable deductions. Depletion will often exceed the basis in a lease; however, the basis should not be reduced below zero.

The Regulations state that, if any grant of an economic interest in a mineral deposit with respect to which a bonus or advance royalty was received expires, terminates, or is abandoned before there has been any income derived from the extraction of minerals, the grantor must restore to income the depletion deduction taken on the bonus or advance royalty. The grantor must also make a corresponding adjustment to his/her basis in the minerals [Treas. Reg. 1.612–3(a) and (b)].

Examination techniques found to be helpful in determining correct basis are as follows:

The following example demonstrates the computation of the adjusted basis for leasehold:

The tax treatment of depletion allowed in excess of the basis of a property sold is explained in by Rev. Rul. 75–451, 1975–2 C.B. 330. Generally, gain on the sale or disposition of property on which percentage depletion has exceeded the basis is limited to the selling price. However, the cost of later capital investments in the property must be reduced by the depletion allowed after the adjusted basis was reduced to zero. The points of the above cited revenue ruling are best illustrated by an example. The taxpayer purchased mineral property for $1,000,000 and sold it several years later for $500,000. Prior to the sale, the taxpayer's allowable depletion amounted to $1,100,000 (this figure includes any cost depletion and percentage depletion taken). The taxpayer's gain would be $500,000. However, if immediately before the sale, the taxpayer invested $300,000 in depletable property, the gain would be $300,000, the sale price of $500,000 minus the basis of $200,000 ($1,000,000 + $300,000 - $1,100,000 = $200,000).

Upon the disposition after 1975 of certain natural resource recapture property, taxpayers are required to recapture as ordinary income all or some part of the IDC paid or incurred after 1975. For oil and gas properties placed in service before 1987, partial recapture of post-1975 IDC is required. For oil and gas properties placed in service after 1986 taxpayers are required to recapture all IDC previously deducted, and depletion deductions that reduced the adjusted basis of the property.

IRC section 1254 requires that gain is treated as ordinary income in an amount equal to the lesser of "IRC section 1254 costs" or the gain realized on the sale or other disposition. The gain realized in the case of a sale, exchange, or involuntary conversion is the excess of the sales price of the property over the adjusted basis. The gain realized on any other disposition is the excess of the fair market value of the property over it's adjusted basis. For this purpose, the adjusted basis shall not be less than zero. Agents should verify this item in most examinations because it is a frequent source of adjustments. Taxpayers should maintain a capital account and a reserve for depletion account for each oil and gas property. All capital investments should be entered in the capital account when the investments are made. All depletion allowed or allowable for income tax should be entered in the reserve account when appropriate. No adjustment is required to either account merely because the reserve account exceeds the capital account. Appropriate adjustments should be made to each account on the disposition of a portion of the property.

Certain dispositions are excluded from recapture. For example, gifts, transfers at death, and transfers in certain tax-free reorganizations. Like-kind exchanges, and involuntary conversions are excluded from recapture only to the extent the property acquired is natural resource property. A lease or sublease is not a disposition. See Treas. Reg. 1.1254–2 for exceptions and limitations.

The sale of a portion of a property or an undivided interest in a property requires the allocation of IDC and depletion — consult IRC section 1254(a)(2) and Proposed Treas. Reg. 1.1254–1(b) for dispositions of a portion of a property.

Oil and gas lease equipment is sometimes sold. The sale is subject to the rules under IRC sections 1231 and 1245. If the holding period requirement has been met, a taxpayer is entitled to IRC section 1231 treatment subject to the recapture of depreciation under IRC section 1245.

Frequently, an entire oil lease will be sold. When this occurs, the sales price must be allocated properly between the lease and the equipment. Usually, the sales contract will specify the sale price of the assets. However, when this is not the case, the sale price should be allocated to the leasehold and the equipment based upon the relative fair market value of each. A petroleum engineer should be requested to make an appraisal of the leasehold and equipment if substantial amounts are involved. See IRM 4.41.1.2.2.4.2 for a full discussion of the allocation techniques.

One problem frequently encountered when depreciable assets are removed from the equipment warehouse and sold is that the taxpayer's book basis may not indicate the correct tax basis. This is due to the customary practice of valuing equipment removed from a lease based upon its condition. This is done in order to pay other owners for their percentage interest. Customarily, the equipment will be placed in the warehouse at the appraised value instead of the adjusted basis. For example, equipment may be valued at 75 percent of the replacement cost if it is in good condition and can be used without additional cost or repairs. The joint owners are paid their share of 75 percent of the new price. Of course, the agent should use the original adjusted basis plus the amount paid to the joint owners as the correct basis for purposes of a sale. See IRM 4.41.1.3.4.1 for discussion of the treatment of equipment transfers under Joint Operating Agreements.

The agent should examine closely the sales instruments when both the leasehold and equipment are sold to determine if the correct allocation is made between the leasehold and equipment. If the taxpayer does not allocate any of the sales price (1) or underallocates (1) to the equipment, the amount of section 1245 gain will be distorted. The agent may obtain an inventory of the equipment sold from the purchaser to use in the verification of the sale price and the basis of the assets sold. The sale of a lease and the related equipment for a lump sum is a potential whipsaw case. In cases in which substantial amounts of money are involved, the agent should make every reasonable effort to obtain consistency of treatment by buyer and seller. The seller's sales price of equipment should be the same as the amount capitalized to equipment by the buyer.

See IRM 4.41.1.2.2.4.2 for further discussion with emphasis on the buyer.

The distinction between depletable and depreciable costs is of major importance when a lease is sold. Each of the seller and buyer will normally attempt to allocate the proceeds in a manner which will produce the most favorable tax advantage for himself or herself.

When a sale of the lease results in a gain, the seller may attempt to assign as much of the selling price to the leasehold as possible. IRC section 1231 treatment will result from the sale of the leasehold, except for the recapture of IDC and depletion under IRC section 1254. A smaller allocation of the selling price to the equipment sold will result in a smaller recapture of depreciation as ordinary income under IRC section 1245.

The purchaser, on the other hand, may attempt to allocate most of the purchase price to depreciable assets, thereby assuring a relatively large depreciation deduction in the future. This is especially tempting when percentage depletion is available.

The buyer and seller may attempt different allocations when the equipment is of high value compared to the lease. This situation may result when a lease and equipment are purchased at or near salvage value. The purchaser will allocate substantially all the purchase price to the leasehold. He/she will then claim cost depletion over a relatively short period of time. The gain from the sale of the salvaged equipment, at substantially more than the allocated original cost, will be treated as IRC section 1231 gain and not IRC section 1245 gain. One of the methods used in computing the correct allocation between leasehold and equipment is indicated in Rev. Rul. 69–539, 1969–2 C.B. 141. The price paid for a going mining business was allocated to each asset or group of assets acquired. This included the mineral lease or mineral property. The purchase price was allocated in the proportion of the fair market value of each asset to the fair market value of all the assets acquired.

In a nontaxable IRC section 351 exchange, the transferee must use the prior owner's basis for depreciation and depletion rather than the actual purchase price and fair market value of the depreciable and depletable assets received. ( Carter Foundation Production Co. v. Campbell , 322 F.2d 827 (5th Cir. 1963); 12 AFTR 2d 5659; 63–2 USTC 89,836.)

A lease can be sold either in whole or fractional shares. Fractional interests are normally made up of two types: working interests and royalty interests. The sale of a fractional part of a working interest normally will result in a IRC section 1231 gain or loss.

The lessee who owns the working interest may assign the property to another and retain an overriding royalty. This transaction would be treated as a sublease, not a sale.

The original lessee may sell one or more portions of the working interest. There can be many different owners of a working interest.

If the lessee sells 1/2 of the working interest for a gain, the lessee will report the gain under IRC section 1231.

If an operator agrees to drill an oil and gas well on a leased tract of land and receives from the lessee, in consideration for drilling, an assignment of the entire working interest in the drill site and an undivided fraction of the working interest in another tract of land, two different transactions have occurred.

If a royalty interest in oil and gas is used by the owner in his/her trade or business, it is not a capital asset. However, it will be subject to provisions of IRC section 1231 if held for more than one year.

A separate property is formed when two or more property owners contribute their separate properties to form one combined operating "unit. " In return for the transfer of property rights, the owners receive an undivided interest in the "unit." Such a transfer generally is considered to be an exchange. Frequently, cash is received or paid as an equalization payment in a unitization. Generally, the cash received will be treated in accordance with the provisions of IRC section 1031.

A production payment that is retained in any transaction except a leasing transaction, occurring on and after August 7, 1969, is treated as a purchase money mortgage and not as an economic interest in the property. Under IRC section 606(c), a production payment that is retained by the lessor in a leasing transaction is treated by the lessee as a bonus payment in installments

Under this rule, if a mineral property burdened by a production payment treated as a loan is sold or otherwise disposed of, the seller of a mineral property who retains a production payment will be taxed in the year of sale on the cash consideration received, as well as the outstanding principal balance of the production payment, subject to the installment sales rules. Thus, the seller will immediately realize gain or loss. Compare Treas. Reg. Section 1.636–1(c)(1) with Treas. Reg. Sections 1.1274–2 & 1.1275–4(c)

The purchaser of a property that is subject to a retained production payment as described in (1) and (2) above will be taxed on all income accruing to the property as if the production payment did not exist and will be entitled to depletion on such income. See Treas. Regs. 1.636–1(a)(ii).

If an owner of a mineral property (or properties) carves out and sells a production payment and the proceeds from the sale of the production payment are pledged for the exploration or development of the property (or properties), the production payment is not treated as a mortgage loan to the extent that the taxpayer that created the production payment would not realize gross income from the property absent IRC section 636(a). Compare Treas. Reg. 1.636–1(b)(1) with Treas. Regs. 1.1273–2 & §1.1275–4(b). It is also necessary that the proceeds be actually used for exploration and development of the property or properties.

Under the conditions cited above, the seller of the production payment is not required to report and pay income tax on the proceeds. The seller of the production payment does not have a basis in the proceeds received. He/she is not allowed a deduction under any section of the IRC for the expenditure of the proceeds. If the money is paid for equipment, the taxpayer has no basis in the equipment purchased. No depreciation is allowable.

Because a production payment that is "pledged for exploration or development" is not treated as a mortgage loan, it is treated as an economic interest in the property (or properties) from which it is paid. The owner of the production payment must report as ordinary income, subject to depletion, all payments received from the production payment. The owner of the property (or properties) from which the production payment was carved has no income as a result of production and sale of oil and gas used to pay the production payment.

Because the "carved out" production payment is unique, its sale and subsequent payout may not be reported properly by the taxpayer. Discovery, by examination, of improperly reported production payments is extremely difficult. The existence of a production payment sometimes can be found on the division order. However, some production payments may not be recorded and may not appear on the division order. In these instances, the record owner receives the income and distributes it to the beneficial owner. If a taxpayer is receiving income from a production payment and excluding it from taxable income, the income from the production payment may be found in bank deposits or other books and records. Unreported income of a corporation usually will be shown on Schedule M.

If a taxpayer has a property on which the income is relatively low compared to operating costs, or the income sharply increases or decreases, it may indicate the existence of a production payment and its creation or termination.

Corporations usually will report large production payments in the footnotes to the financial statements.

The agent should ask the taxpayer, or representative, if any of the properties are burdened by production payments.

If existence of a production payment is discovered and appears material, the agent should study the documents that created the production payment so that he/she may make a proper decision as to its treatment. The agent should then check the taxpayer's treatment to see that it is proper.

Since the examination of carved out production payments can be time consuming, the agent should use judgment as to how far this issue should be pursued.

Rev. Proc. 97-55, 1997-2 C.B. 582 sets forth the conditions under which the Service will entertain the issuance of an advance ruling to the effect that a right to production is a production payment subject to IRC 636.

The conditions are:

The question that arises is "what will happen if there is a sale of a carried interest?" There are two sides to consider.

If the "carry" is for a period of time less than the entire productive life of the lease, the sale may be viewed as either a carved out production payment or the sale of a working interest depending upon the facts.

If a taxpayer sells a lease interest that is burdened with a carry, the taxpayer may be entitled to some capital gain treatment, as in the Frazell case, where maps were included as part of the property interest ( Frazell v. United States , 335 F2d 487, 14 AFTR 2d 5378 (5th Cir. 1964); reh. denied 339 F2d 885, 14 AFTR 2d 6119 (5th Cir. 1964), cert. denied, 380 U.S. 961).

Lease brokers are common in oil and gas producing areas. If the property sold is held by a broker for sale in the normal course of the business activity, the taxpayer will be considered a dealer and the income will be ordinary income. IRC section 1231 will apply, however, to the gains from the sale of leases by a dealer or broker if the dealer can establish that the property was held for investment purposes only. Therefore, some taxpayers may be both a dealer and an investor.

Rev. Rul. 73–428, 1973–2 C.B. 303, addresses itself to the sale of a royalty interest in oil and gas in place. If the interest is used by the owner in his/her trade or business, it is not a capital asset but will be subject to the provisions of IRC section 1231 if held for the required length of time. If the royalty is held for investment, gain or loss on its sale is a capital gain or loss. If the royalty is held for sale in the normal course of a taxpayer's business, ordinary gain or loss will result.

The courts have used various factors in determining whether an individual is a dealer or an investor. Listed below are two cases which highlight these factors.

In Spragins v. United States , (D. C. Tex. 1978); 42 AFTR. 2d 78–5389; 78–1 USTC 84,323, the court decided that the taxpayer held certain oil and gas leases for investment not for sale in the ordinary course of business. Thus, the taxpayer was entitled to capital gain treatment. The court found that Spragins was, in fact, primarily an oil and gas producer. Spragins did not advertise leases for sale. Most of his gross income came from 31 producing oil and gas properties. He, in fact, drilled seven wells, abandoned six leases, operated several properties, and sold only five properties. The court determined that the properties were not held for sale in ordinary business activity but were held for investment.

In Bunnel v. United States , (D.C.N.M. 1968); 20 AFTR 2d 5696; 68–1 USTC 86,054, a jury determined that oil and gas leases had been held by the taxpayer primarily for sale to customers in the ordinary course of business. Therefore, gain realized upon the sale of leases was subject to treatment as ordinary income instead of capital gain. No single factor is controlling in determining if the property is held for sale to the customer in the ordinary course of business. Consideration must be given to all the facts. In the above case, the jury was charged to consider the following facts in making their determination:

The sale of oil properties will usually be reflected on Schedule D. The agent must use his/her judgment in determining whether the taxpayer is a dealer or investor. The guidelines shown in the above cited cases should be followed in determining the correct classification of the taxpayer-dealer or investor. This is a difficult issue that will be decided by the facts in each case. The agent must obtain all of the facts concerning the number of leases sold, the taxpayer's primary business, the extent of advertising, etc., before proposing to treat a taxpayer as a dealer.

Geological and Geophysical (G & G) data obtained through exploratory and seismic activities is frequently exchanged and/or sold to other parties interested in the hydrocarbon potential of a given area. Brokers are active in the sales, swaps, and exchanges of this data. Many times the taxpayer will sell geological data after it has been deducted as G & G expense or an abandonment. Care should be used in the verification of any basis claimed on the sale of data.

There are a number of companies that gather G & G data, for the purpose of selling it to other parties interested in exploring for oil and gas.

The examiner, in the beginning of the examination, should obtain a list of canceled leases showing project identification, lease identification, cost, and date acquired. Verify the bases of the leases canceled, and determine if any portion of any one of the leases written off is in a unitization project.

Determine if the property charged off has been top leased in a subsequent year; and check to see if title to the property is still held by the taxpayer. An easy way is to check delay rentals paid on the leases that have been abandoned.

Allowance of a deduction for worthlessness should not be based on the consideration of only one or two factors. A good judgment can be made only when all of the facts are known.

In auditing abandonment losses, examiners should first look to the abandonments themselves and ask the following questions:

Examiners should be aware of the timing difference between worthlessness and abandonments. However, a practical approach must be used in deciding whether or not to make roll over adjustments.

A forfeit of a lease may occur when the production of the lease falls to the point where it is not profitable to continue the lease. In a productive lease agreement, the terms generally call for forfeiture of the lease 90 days after production stops. In a nonproductive lease, the forfeiture of the lease may occur when the taxpayer fails to pay the delay rental.

Examiners should be aware that, in general, delay rentals are not based on a calendar year.

Top leasing occurs when the taxpayer extends the lease prior to the expiration of the original lease. When top leasing occurs, the IRS will not recognize any abandonment losses on the original lease. When the taxpayer extends the original lease, the agent does not have much of a problem since the extension is a continuation of the old lease and readily available upon examination.

The main problem in top leasing occurs when the taxpayer extends the lease by obtaining a new and separate lease on the old property. This fact usually is not readily apparent to the agent; and the agent may allow the abandonment under the assumption that the original lease has terminated, when, in reality, it has not. Finding a top lease is difficult. Two methods of determining whether a top lease exist are: