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:

Intangibles and Delay Rentals. The election to expense intangible drilling and development costs must be made by a taxpayer in the return for the first year in which such costs are first paid or incurred. See IRC section 263(c)(i) and Treas. Reg. 1.612–4. The election is made by claiming the intangible drilling and development costs as a deduction on the return and, when made, is binding for all future years. This election includes the right to deduct intangible drilling and development costs on productive and nonproductive wells. The failure by the taxpayer to deduct such expenses is deemed to be an election by the taxpayer to capitalize such costs. Such capitalized costs are thereafter recovered through the deductions of depletion. However, for treatment of IDC paid or incurred after 1982, see IRC section 59(e), IRC section 291(b), and IRM 4.41.1.2 and IRM 4.41.1.2.4.3. Delay rentals are required to be capitalized under IRC section 263A.

Taxpayers who are co-owners of oil and gas properties and have not elected to be excluded from the partnership provisions of Subchapter K of the Code must make a partnership level election to expense intangible drilling and development costs. If the partnership elects to capitalize such costs, the individual partners are bound by that election and may not deduct those costs on their individual returns.

For the purpose of computing allowable depletion and any gain or loss on the disposition of oil and gas minerals, the term "property " is important. The term "property" means each separate interest owned by the taxpayer in each mineral deposit in each separate tract or parcel of land. See IRC section 614. The Code provides that all of the taxpayer's operating mineral interests in a separate tract or parcel of land are to be treated as one property unless taxpayer elects to treat such interests as separate properties. The election to treat each property as a separate property must be made in the first year the taxpayer makes any expenditure for development or operation of the property interest. The election must be made by attaching to the return a specific statement describing the tract and all the operating interest owned in the tract and must indicate which operating interests are being combined and which are being kept separate. Once the election is made, it is binding for all subsequent years.

The agent should make sure that the taxpayer is combining all income and expenses from the properties on tracts that are producing from different zones unless the proper election has been made to treat them separately.

The income from different types of oil and gas activities are reported by individuals on different schedules on their Form 1040. Royalty income is reportable by an individual on Form 1040, Schedule E. Income received from lease bonuses and delay rentals is also reported on Schedule E. Royalty income is usually not trade or business income and is generally not subject to self-employment taxes. Royalty owners do not pay production expenses other than taxes.

An individual taxpayer who owns a working interest reports income from the sale of oil and gas on of Form 1040, Schedule C. This income is considered trade or business income.

The losses realized from certain "activities" are limited to the amounts a taxpayer has "at-risk" with regard to those activities at the end of the tax year. The otherwise deductible loss from the "activity" of exploring or exploiting oil and gas reserves could be limited by the at-risk rules of IRC section 465. Each separate oil and gas property constitutes a separate activity for purposes of IRC section 465. Any losses which are limited by this section will be allowed as a deduction in the next succeeding tax year, provided there is additional at-risk basis of property at the end of that year. The amounts a taxpayer has at-risk with respect to an activity are as follows:

Examining agents need to keep in mind that in order to deduct losses from oil and gas activities, individuals must have a sufficient amount at-risk within the meaning of IRC section 465. This can be thought of and is sometimes referred to as "at-risk basis" . For example, if the taxpayer is engaged in a drilling program that is financed with borrowed funds and the leases are operating at losses, the examination should be extended to verify that the at-risk provisions of the law are being met. If the at-risk limitations are found to apply to a given oil and gas property, the transfer of lease equipment from that property to another property could trigger a realization of ordinary income under IRC section 465(e) since the assets at risk with respect to that particular activity have been decreased. Disposition of a property is not necessary for ordinary income to be realized; reduction of at-risk basis below zero can create income realization.

The typical oil and gas working interest owner or joint venture is a member of a partnership although he/she may account for his/her income and expense separately. See the definition of the term "partnership " under IRC section 761.

IRC section 761(a) and Treas. Reg. section 1.761–2(a)(3) and (b)permit participants in the joint production, extraction, or use of property to be excluded from the partnership code sections in Subchapter K. This election is made by attaching a statement to a partnership return. The election can be made in any year in the life of a partnership, including the first year. However, until the election is made, a partnership return must be filed and the joint venture will be subject to the partnership provisions in the Code. Once the election is filed, the joint venture ceases to file a partnership return, and the joint interest owner or working interest owners may not consider themselves to be partners.

If a partnership does not elect to be excluded from Subchapter K, the partnership itself must make all elections affecting taxable income of the partnership, except for any election under:

IRC section 703 and Treas. Reg. section 1.703–1(b) provide for elections that are made by the partnership instead of by individual partners. The most important election made by an oil and gas partnership is the election to capitalize or deduct IDC. The election to deduct currently or capitalize must be indicated on the first partnership return claiming such expenses. Failure to elect to deduct IDC on a partnership return will sometimes preclude the passthrough of lDC to the individual partners. Frequently, taxpayers fail to realize that a partnership return must be filed, and they fail to elect to be excluded from the provision of Subchapter K. When this happens, the election to deduct IDC currently cannot be made by the partnership; therefore, IDC may be capitalized at the partnership level. Moreover, in cases where a partnership does elect to expense IDC and passes through the IDC deduction to its partners, the partners may elect to capitalize and amortize IDC as provided in IRC section 59(e) for alternative minimum tax purposes.

If the partnership elects to be excluded from the provisions of Subchapter K, each partner will make the election to capitalize or deduct IDC. If the partners have made a previous election, they will be required to follow it.

Elections should be made at the partnership level with respect to the following expenditures:

A discussion of oil and gas tax law would not be complete without a discussion of IRC section 704. You will remember from your previous study of partnerships that a partner's share of income and deductions will be determined from the partnership agreement. Enterprising oil and gas promoters use this provision of law to allocate current deductions to investors who furnish money for drilling wells.

Generally, the pure economics of drilling a wildcat well do not offer sufficient benefits to entice outside investors to furnish money for drilling. However, if the general partner or promoter can allocate all of the current tax deductions to the investor, often the tax benefits are sufficient to justify the investment. IRC section 704(b) permits unequal allocations of deductions among partners as long as the allocation has substantial economic effect. For an illustration of the substantial economic effect rules, see Orrisch v. Commissioner , 55 T.C. 395 (1970); aff'd, 31 AFTR. 2d 1069 (9th Cir. 1973).

Where an allocation does not affect the partner's capital upon liquidation, it will not usually be considered to have substantial economic effect. In such a situation, if the allocation is determined to lack substantial economic effect, the item will be reallocated in accordance with the partners’ interest in the partnership. Generally, this means the item will be shared among the partners on a per capita basis. An easily understood discussion on partnership allocations can be found in The Logic of Subchapter K by Laura and Noel Cunningham, American Casebook Series, 2nd Ed.Ed., the West Group (St. Paul, MN).

All partnerships incur certain formation costs such as legal fees, officers' salaries, administrative expenses, and broker's fees for selling partnership units or shares. Sometimes these expenses are paid by the general partner, promoter, or sponsor and sometimes they are paid by the partnership. After October 22, 2004, if the partnership elects, the partnership can deduct the lesser of (i) the organizational expenses with respect to the partnership or (ii) $5,000 reduced (but no below zero) by the amount that organizational expenses exceed $50,000. Any remaining organizational expense is allowed as a deduction ratably over 180 months.

On or before October 22, 2004 costs of forming a partnership are capital in nature and are not allowable as a current deduction (see IRC section 709(a)). IRC section 709(b) does, however, permit amortization of organization fees over a 60-month period.

Formation costs may not be evident in the partnership return or in the books and records of the partnerships. When this is the case, such costs can be found on the return of the partnership sponsor or promoter. Therefore, the agent should review and, if necessary, examine the sponsor, promoter, or general partner concurrently with the examination of the partnership so that the proper treatment of these costs can be ascertained.

In large limited partnerships, it is a usual practice to sell partnership units through a stock brokerage firm. These firms usually charge a commission ranging from 5 percent to 10 percent of the entire partnership capital. These costs are syndication costs (rather than organization costs) which cannot be deducted or amortized. This can be a rather sizable adjustment and can usually be found by a careful reading of the partnership prospectus.

Large management fees paid in the first year of the partnership can be an indication that the partnership is reimbursing the sponsor for formation costs. A careful reading of the prospectus and inquiries to the managing partner can uncover this issue. However, in some cases, an examination of the sponsor's books and records is the only way to accurately determine the actual amount and nature of the formation costs.

While you can usually speculate that a certain percentage of the first year management fee is for formation costs, your determination may not be sustained if a taxpayer later purports to show the actual formation costs to an appeals officer or to the court. Therefore, it is advisable to determine the actual amount and nature of the organization costs instead of relying upon an arbitrary percentage for your adjustment. See IRC section 709.

The Tax Reform Act of 1975 added IRC section 703(a)(2)(F) to provide that the deduction for depletion under IRC section 611 is not allowable as a deduction to a partnership. Therefore, after January 1,1975, the depletion deduction must be deducted on a partner's return, not the partnership return. Due to IRC section 613A, each partner must now compute the limitations for their depletion deduction on their own return. Each partner treats an allocable portion of the partnership's basis in the property as his or her own basis for cost depletion computation purposes. Treas. Reg. section 1.613A-3(I) provides that the partnership is responsible for providing each partner with the information necessary to compute his depletion deductions.

Your previous study of special partnership allocations such as losses and depreciation are equally valid in oil and gas partnerships.

As noted above, common practice in oil and gas partnerships is for currently deductible costs to be allocated to certain partners. For instance, intangible drilling costs, well completion costs, and operating costs may be allocated entirely to limited partners. Special allocations are permitted under IRC section 704, but they must have substantial economic effect. A review of IRC section 704(b) and Treas. Reg. section 1.704-1(b) will provide guidance in this area. In addition, Chapter 6 of the MSSP Guide on Partnerships (Training Order No. 3123-071, 9/2002) provides understandable examples.

Examiners should not accept a canceled check as proof of the amount of the deduction for intangible drilling and development costs without additional supporting documents. Frequently, promoters and sponsors of oil and gas ventures inflate the actual drilling costs to include an excessive profit for themselves. In some cases, examiners have found that the lDC are inflated several times over the actual costs. The amount in excess of the actual cost plus a reasonable profit should be considered to be paid for leasehold cost and capitalized by the partnership. See Rev. Rul. 73–211, 1973–1 C.B. 303. When the reasonableness of drilling costs are in question, the examiner should consult a petroleum engineer.

Oil and gas wells vary in depth according to the area, drill site location, and formation to be tested. It is much more expensive to drill a deep well than a shallow well. The drilling cost per foot of hole is much greater for a well drilled to a depth of 15,000 ft. than for a well drilled to 1,000 ft. There are several reasons why the drilling costs per foot are not constant. The area of country, environment, rock formations, and other factors contribute to the ease or difficulty of drilling a hole. Other factors are the size and quality of the equipment. At deep depths, greater pressure and drill stem weight require larger drilling rigs, pumps, drill stem, surface casing, mud, etc.

As an example, a well drilled to a depth of 5,000 ft. in west central Texas will differ substantially from the cost of a well of the same depth in Louisiana. The difference in the price per foot of well drilled might be five times greater for offshore Louisiana. In 1999, the average cost in the U.S. was $139 per foot for onshore wells and $514 per foot for offshore wells. As stated above, the cost of a well will vary according to area, depth, location, and other factors. Therefore, the costs above represent estimates only and should not be relied upon as more than that. An agent should consult an IRS petroleum engineer whenever he/she doubts the validity of actual drilling costs.

Frequently, a general partner or sponsor of a partnership will acquire an oil and gas lease from a landowner or by taking a "farm-in, " and transfer the lease to a partnership as a capital contribution.

Usually the lease cost is nominal, and the limited partners never pay for any lease cost. The limited partners do actually pay for the leasehold interest indirectly by paying more than their share of the lDC. However, this is permitted under present law if the special allocation has substantial economic effect. On the other hand, if the leasehold cost is substantial and the amount paid by the limited partners for IDC appears to be excessive, the agent should determine if the general partner has made an excessive profit on IDC from the drilling contract. If this is the case, the excessive amount of IDC should be considered to have been paid for the leasehold interest and capitalized accordingly. See Rev. Rul. 73–211, 1973–1 C.B. 303.

A partner’s share of losses incurred by a partnership in a trade or business should be deducted on his Form 1040, Schedule E as an ordinary loss. However, IRC section 704(d) limits the loss deduction to the partner's basis in his partnership interest, computed at the close of the year. The loss disallowed is suspended and can be deducted in later years if the partner's basis in the partnership interest increases above zero. See also IRC sections 465 and 469 for additional loss limitations.

Losses from the sale of capital assets retain their character and pass through separately to the partners. Normally, the sale of oil and gas leases and of equipment on oil and gas leases are considered to be sales of assets used in a trade or business and, thus, are treated as IRC section 1231 property.

Prior to the Tax Reform Act of 1976 , promoters of oil and gas drilling ventures often utilized nonrecourse loans to provide deductions for limited partners in excess of their economic investment. This practice was questionable at best and generally lacked economic substance. IRC section 465(b)(6) now provides that the deduction for losses incurred in oil and gas ventures (among other activities) cannot exceed the amount "at-risk." . Therefore, normally a limited partner's loss deduction cannot exceed the money invested. Agents should closely scrutinize promoter financing for these ventures.. Usually the loans in most contemporary drilling ventures will be guaranteed by the partners and backed up with solid collateral. If this is the case, the loan is recourse and will increase the basis of the party who provides the collateral and guarantee. See IRC section 752. If a limited partner does not guarantee the loan, he will not be considered at risk since he is protected from recourse on the loan due to his status as a limited partner. His deductions would be limited accordingly. Note that the at risk rules are generally applicable to individuals and only in very limited circumstances to closely held corporations.

A productive well has value and will increase the value of all the leased acreage surrounding the drill site. At this stage, a lending institution would likely make a legitimate loan on the property assuming the well is a good one and the partners obtained an appraisal from an independent geologist. In such a situation, the partners' at-risk basis would be increased if the loan were a recourse loan – that is, if the partners were personally liable for repayment of the loan. Where situations of this kind exist, a careful reading of the underlying documents and IRC section 465 is in order. In cases where a partnership loss is involved, loans that increase a partner's basis and amount at risk must be looked at carefully to determine if the loans are legitimate.

IRC section 721 states that no gains or losses shall be recognized to a partnership or any of its partners when property is contributed to a partnership in return for an interest in the partnership. IRC section 722 provides that the basis of an interest in a partnership acquired by a contribution of property shall be the amount of such money and the adjusted basis of the contributed property other than money. Generally, no recapture of investment credit, or amounts under IRC sections 1245 (b)(3), 1254 and Treas. Reg. 1.1254–2(c) will be triggered by a contribution of property by a partner to a partnership.

However, the nonrecognition provisions of IRC section 721, et. al., do not apply to a transfer of property where a party is not acting in the capacity as a partner. See Treas. Reg. section 1.721–1(a). The substance of a partner-partnership transaction should govern instead of the form. If a partner sells property to a partnership for money and notes, the transaction should be treated as a sale in accordance with IRC section 707.

A frequent occurrence in oil and gas partnerships is for limited partners to supply funds for IDC and receive an interest in the partnership of 50 to 60 percent. The sponsor or general partner will furnish his/her services, a lease, and depreciable equipment, if needed, in return for a 40- to 50-percent interest in the partnership. Treas. Reg. section 1.721–1(b)1 provides that, if one partner gives up a part of his/her right to be repaid contributions of capital in favor of another partner who renders services, IRC section 721 will not apply. The Regulations further provide that the "value of interest in such capital so transferred to a partner as compensation for services constitutes income to the partner under IRC section 61. The amount of such income is the fair market value of the interest in capital so transferred. " In all cases where a partner receives a transfer of capital from another partner for rendering services, agents should carefully scrutinize the transaction. If the capital contributed by a partner will not be returned to him/her upon liquidation of the partnership, the partner who receives the capital may be in receipt of income if he/she provided the services. On the other hand, if the partner receives a profits interest rather than a capital interest in the partnership, the receipt of such an interest is not ordinarily a taxable event for either the partner or the partnership unless: 1) the profits interest has a fairly certain income stream; 2) the interest is in a publicly traded partnership (within the meaning of IRC section 7704(b)); or 3) the service partner disposes of the interest within two years of receipt. Additional sources of information on this issue include: