Referrals to engineers are made on the Specialist Referral System which can be accessed through the internet (LMSB home page under Field Specialists). This referral should be made during the early stages of each examination when significant and complex engineering issues are noted on the return.

In the course of the examination, the agent should request the assistance of a Computer Audit Specialist (CAS). The CAS should be involved in the review of records for record retention evaluations and to assist the agent as appropriate throughout the examination. The CAS is also trained in the use of Statistical Sampling techniques.

In those instances where the volume of records is such that a 100 percent examination is not feasible, statistical sampling should be considered.

Referrals to CAS are made on the Specialist Referral system which can be accessed through the internet (LMSB home page under Field Specialist).

The Industry Director (Natural Resources & Construction) has been delegated the authority to determine:

The above issues are referred to as controlled issues. Revenue Agents handling cases that involve a taxpayer who engages in inter or intra company sales of crude oil or refined products or in inter or intra company transportation, must refer the case to the Industry Director (Natural Resources & Construction).

The referral is made directly to the Petroleum Industry Program on Form 5593 (Controlled Issues in Oil Pricing Cases Report) who reviews the issue on behalf of the Industry Director (Natural Resources & Construction). For further information see IRM 4.40.4.

Referrals to International Examiners (IE) are made on the Specialist Referral System which can be accessed through the internet (LMSB home page under Field Specialist) during the early stages of each examination initiated by a revenue agent when it is ascertained that the taxpayer is engaged in business outside the United States either directly or through related, controlled, or controlling affiliates (see the International Procedures Manual at IRM 4.60.6 and IRM 4.60.5). Since IRC section 482 allocations may be possible in these cases, it is important that the referral reflect all such subsidiaries controlled by the corporation being referred.

When, in the course of the examination, the agent discovers claims for excise and employment tax payments, the assistance of a specialist should be requested by the agent through his/her manager to the appropriate excise and employment tax specialist manager.

Referrals to the specialists in TE/GE are to be made through the agent's manager when the agent encounters complex and extraordinary deductions relating to matters that involve Employee Plans (pension and profit sharing plans), Exempt Organizations, Indian Tribal Governments, Tax Exempt Bonds or Federal State and Local Governments. The agent's manager must contact the Office of Indian Tribal Governments to coordinate any first contact with an entity owned by an Indian tribal government or situated on Indian land (see IRM 4.86.1.1.3, Coordination Between Divisions).

Examiners are encouraged to become familiar with the numerous petroleum industry trade publications. Frequently, these publications will contain industry statistics that are very useful in the examinations of oil and gas issues.

For instance, the selling prices of domestic and foreign crude oils are sometimes shown in periodicals. A comparison of these industry average prices with the purchase price paid to a Controlled Foreign Corporation (CFC) will sometimes point out "pricing" problems between related entities. Another use of industry statistics is a comparison of drilling costs with the costs reported on the tax return being examined. While average drilling cost statistics are not reliable for purposes of making adjustments, comparisons will often point out problems that might not be easily identified under normal examination techniques. An apparent excessive drilling cost may be easily explained as being due to accidents, such as losing the drill string. On the other hand, the excessive cost may be the result of excessive charges or due to the inclusion of lease cost in the IDC billed to joint owners.

The wide use of industry statistics can materially reduce examination time. Furthermore, their use as a testing tool will frequently identify problem areas that would not be found using normal examination techniques. IRS engineers will usually have access to current petroleum industry statistics. The Technical and Research Section of the PIP will also usually have current statistics.

Oil and gas exploration and production is closely supervised and regulated by the various state agencies. Virtually every state has different requirements, and the agencies within each state that administer the laws are varied.

One of the resources available to examiners with respect to a description of the various actions taken on oil and gas properties are the various state permits required to be obtained before any type of drilling, exploration, deepening, plugging and abandoning, etc., can be done. The applications for the various permits and reports of work performed filed with the state agencies provide a wealth of helpful information, such as dates of notices of intention to drill a well, type of well, legal description of property, estimated total depth, etc.

Production severance tax rates imposed on oil and gas production by the various states have not been shown on the attached schedule because of the many differences in the rates and manner in which applied. This knowledge is, however, important to the examiner because, in many instances, investors will report the net amount of the proceeds received from the sale of oil and gas as gross income subject to depletion. Gross income; for depletion purposes, means gross revenue before payments of severance taxes. The tax rates, and how they are applied, may be obtained from the taxpayer or from the state agency that administers the tax.

The type of ownership interest determines the extent to which the investor and operator will share in the income from oil and gas production. The various kinds of property interests or rights constitute the ownership of the oil and gas extracted. IRC section 614 defines a property as each separate interest owned in each mineral deposit in each separate tract or parcel of land.

An understanding of the tax consequences of oil and gas transactions requires a clear concept of mineral interests and their interrelationships.

The interest begins with the landowner. He/she owns the land in fee, including the minerals on and beneath the surface. The landowner may sell or otherwise dispose of subsurface or mineral rights without relinquishing his/her surface rights.

Our concern here is with the ownership of the mineral rights, which includes the total of all rights to the oil and gas in place. The mineral rights, or total rights to the oil and gas in place, include:

Remember that the owner of the mineral rights can be someone other than the landowner. The owner of such mineral rights can sell or otherwise dispose of his/her ownership or interest in the minerals. When such dispositions are made, other interests and new owners come into the picture, each having a piece of the mineral deposit. These interests entitle the owners to share in the total production from the property.

A landowner generally owns what is known as a "fee interest, " which consists of the ownership of both surface and mineral rights. The landowner can sell or lease all or any part of the land or minerals. A lease agreement usually provides for a cash consideration, or bonus, and a royalty to be paid to the landowner. The lease usually contains a provision for the lessee to pay a delay rental for each year development is not started or forfeit the lease.

Cash bonuses received upon the execution of an oil and gas lease are regarded, for income tax purposes, as advance royalties. The Supreme Court in Anderson v. Helvering , 310 U.S. 404, 409 (1940); 24 AFTR 967; 40–1 USTC 553, stated " cash bonus payments, when included in a royalty lease, are regarded as advance royalties, and are given the same tax consequences." Bonus payments are not subject to percentage depletion after August 16, 1986 because of the enactment of IRC section 613A(d)(5).

In any subsequent year during the term of the lease, the receipt of the delay rental will be ordinary income to the landowner on which no depletion is allowable. The delay rental is not an advance payment for oil but is in the nature of rent paid for the privilege of deferring development. See Treas. Reg. 1.612–3(c)(2)

If drilling results in a producing well, the landowner will receive periodic payments for his/her share of the production in accordance with the terms of the lease. These payments, called royalties, are ordinary income to the landowner. This income is subject to percentage depletion to the extent provided in IRC section 613A and the Regulations provided thereunder, provided that percentage depletion is greater cost depletion. This will usually be the case when the fee interest in the entire property is acquired for the purpose of using the surface rights and, as a result, the landowner will have no basis in the mineral rights.

If there is no production and the lease expires, the depletion previously allowed against bonus income must be restored to income in the year the lease terminates. However, restoration of depletion on the bonus is not required if the taxpayer who owned the property and took depletion on the bonus has completely divested himself/herself of all the property prior to expiration of the lease without production. See Treas. Reg. 1.612–3(a)(2)

Termination of the lease may be indicated by the absence of the delay rental in the income of the current return and its presence in the prior return.

If, prior to expiration, the lease was extended and a bonus was paid for such extension, percentage depletion would be allowable on the bonus only if reportable prior to August 16,1986. See Treas. Reg. 1.613A–3(j). After that date, taxpayers may still compute cost depletion on these payments. Restoration to income of bonus depletion would not be required with respect to the original lease or the extension unless the lease terminated without production and depletion had been deducted. See Treas. Reg. 1.612–3(a)(2). At such time, the allowed depletion on the original lease and renewal (top lease) should be included in income.

The landowner can sell all or any part of the mineral rights. If he/she sells a fee interest in the minerals, the sale is governed by the provisions of IRC section 1231. If the sale of the property otherwise qualifies as provided in IRC section 1231, a long-term capital gain is realized on the sale of minerals. There is no cost basis unless one of the following conditions exists:

The basis is applicable in the event of a sale or for computing cost depletion. Generally, the basis of minerals should not be allowed as an abandonment loss where the owner also owns the land.

The agent should inspect the prior-year return. The prior-year return may disclose a delay rental which does not appear in the current return.

This indicates for the current year either unreported income from delay rental or a lapsed lease which may require restoration of bonus depletion by the lessor.

Experience has indicated that bonus income and royalty income are usually reported, but bonus depletion is rarely restored to income.

The position of a fee royalty owner is the same, irrespective of whether he/she owns the surface rights. He/she may lease his/her interest, receive a bonus or delay rentals, receive income from production, and may sell all or any portion of his/her fee royalty interest.

Rights or interest in production may be created by the owner of the minerals and consist of two major categories: Royalty Interest and Working Interest.

A royalty interest entitles its owner to share in the production from the mineral deposit, free of development and operating costs, and extends undiminished over the productive life of the property. See Treas. Reg. 1.636–3(a)(2) for situations where a royalty will be treated as a production payment.

A working interest also entitles its owner to share in the production, but this owner must bear his/her share of the development and operation costs.

Royalty and working interest owners may, subject to certain restrictions, sell or otherwise dispose of all or part of their respective interests in the total production. When this happens, there are additional subdivisions of the total production known as overriding royalties, oil and gas production payments, net profits interest, carried interest, etc.

Exhibit 4.41.1-2 shows a diagram of some of the divisions of production from oil and gas. Beginning with the landowner, this is carried through a few of the various interests which may be carved out of the original ownership of the minerals in place.

Up to this point, our discussion has been purposely brief to cover only a general idea of oil and gas transactions. In the subsequent sections, we will cover in detail the various economic transactions involving oil and gas interests and the tax consequences as they relate to examination techniques.

The fee royalty generally will represent the landowner's retained interest for the oil or gas in place. Traditionally, the amount of the fee royalty is 1/8 of the production from the property. The remaining 7/8 is generally conveyed as working interest to an operator in consideration for a cash bonus and development of the property. Another type of royalty is known as an override, which is an interest reserved or carved out of the 7/8 working interest, the life of which is coexistent with that of the lease or working interest. Usually the life of the fee royalty is perpetual. However, its life may be limited by the terms of the instrument under which it was created. In some areas, the life of a fee royalty may be governed by state law.

There are two types of royalty interest which may be acquired from the landowner. In one, the landowner conveys by royalty deed the title in fee simple to all or a portion of the landowner's royalty interest in the property. The deed may describe the interest sold as a fraction of the " landowner's royalty" or a number of "royalty acres." Each royalty acre is entitled to a fraction (usually 1/8) of the production attributable to that acre, free and clear of production costs. This transaction may take place before or after leasing. The interest thus assigned is a fee royalty. In the other type, the landowner, after leasing, may sell portions of his/her royalty interest in the lease. This is not a fee interest, but a share of the production of oil or gas under this lease, and expires with the termination of the lease. In this respect, it is similar to an overriding royalty.

The royalty interest is purchased from the landowner, who may sell his/her entire interest, or any fraction thereof. Usually this is after a lease has been granted for the development of the property and there appears to be a prospect of future production. The purchase is usually made by an investor or royalty dealer. The principal issues encountered here are the treatment of acquisition costs and deductions for worthlessness losses claimed as a result of unsuccessful exploration.

The small investor may maintain ledger control accounts of producing royalties and nonproducing royalties. These are supported by a subsidiary ledger having separate sheets for each property interest (particularly producing properties) and usually showing the property interest owned. He/she usually has the recorded instruments of conveyance for inspection if they are needed.

The larger investor may maintain control accounts of Producing Royalties and Nonproducing Royalties, and a subsidiary record known as a Royalty and Fee Land Record for each royalty interest owned. Such record shows the property, location, description, interest owned, from whom acquired, date acquired, cost, lease information, and record of rentals received. When verifying cost for an investor who has claimed an abandonment loss, the agent should verify that the cost has been removed from the subsidiary record as well as the control account. The cost may have been written off for tax purposes without appropriate charges on the books. When a royalty becomes a producing property, the investment account is transferred from the Non-producing Royalties account to the Producing Royalties account. At this point, the property should be shown in the return as income producing property subject to depletion.

The royalty dealer usually watches oil company leasing operations very closely. When an area of interest comes to his/her attention, the dealer begins purchasing the fee royalties in the area. He/she usually has certain investors with whom he/she regularly deals, and to whom he/she sells a portion of the royalty interest acquired, retaining a small fraction as his/her own investment. The dealer usually sells a portion of the royalty obtained for a greater sum than the entire cost of the interest obtained. He/she must retain a fraction of the cost corresponding to the fractional interest retained. Thus, if a dealer purchases 1/16 royalty (1/2 of the landowner's 1/8) for $8,000 and sells a 3/64 interest (3/4 of his/her royalty), the basis for the portion sold is $6,000. The basis of the 1/64 interest retained is $2,000.

The investor or dealer should capitalize, as part of the cost of royalties, commissions, title examination and recording fees, travel expense, or other expenses incurred in connection with the acquisition of the royalty interest. If a single sum was capitalized as cost of the royalty, this may indicate that some of the above acquisition costs were charged to expense. This would require an analysis of certain expense accounts.

Amounts paid or incurred for geological and geophysical before enactment of the Energy Tax Incentives Act of 2005 should be capitalized pursuant to Rev. Rul. 83-105. However, amounts paid or incurred for geological and geophysical after enactment of the 2005 Energy Bill should be amortized over two years under IRC section 167(h). See Exhibit 4.41.1-29) After May 17, 2006, the geological and geophysical amortization amount for certain integrated oil companies were extended to five years. (See Exhibit 4.41.1-30 )

Acquisition costs must also be allocated to the cost basis of the specific royalties acquired. Where multiple royalties are acquired, it may be difficult to determine the accuracy of the taxpayer's allocation of travel, geological, geophysical, and general office expenses.

The interests of an investor or operator in mineral deposits (and his/her right to share in the production from such deposits) are governed by the terms of a leasing contract or supporting agreement. Through these contracts, there may be numerous assignments, conveyances, and dispositions of interest or rights.

By analyzing the various leasing contracts and the resulting tax consequences, you can pick up leads to potential tax adjustments. You may find that a substantial amount of your examination time will be spent in such analyses. This is a very important examination step.

The oil and gas lease has progressed from a simple crude instrument to a complex document. Basically, however, most leases are similar in that they contain eight principal elements.

While all such leasing contracts may contain these basic elements, the variations in their wording and meaning are numerous. These contracts vary to such an extent that it would be impractical to talk in terms of a "typical contract." This very feature emphasizes the importance of your analysis.

When examining the lease record for properties acquired during the year, pay particular attention to the amount of rent per acre per year. You may find something to indicate payments other than normal delay rental. In most areas, delay rentals are relatively small compared to lease bonuses. The period covered by the lease should be noted, as well as any provisions with respect to terms and expiration. The purpose is to be sure an installment bonus is not recorded as a delay rental.

Oil and gas lease agreements generally provide for the lessee to begin drilling for oil and gas on the property within one year after the granting of the lease. If drilling has not begun within this period of time, the lease agreement will either expire or provide for the payment of a sum of money in order for the lessee to retain the lease without developing the property. These payments are known as "delay rental" payments and are made in order to be granted additional time in which to drill and develop the leased property. The purpose and the rights granted by the payments of the rental must be examined to determine whether the payments are actually "delay rentals," lease bonus, or royalty payments. Delay rentals are not payments for oil or gas to be produced. They are paid for the privilege of retaining the lease without drilling for up to another year.

Delay rentals are ordinary income to the recipient and are not subject to the depletion deduction. See Treas. Reg. 1.612–3(c). The payment of delay rentals are preproduction costs which are required to be capitalized to the depletable basis of the lease pursuant to IRC section 263A if the lease is held for development or if development is reasonably likely at some future date. See Treas. Reg. 1.263A–2(a)(3)(ii), TAM 9602006 and Coordinated Issue Paper dated September 19, 1997.

A small operator may keep a simple set of records. A large operator will probably keep a rather complex system of records. Each operator maintains separate accounts of producing and nonproducing properties. Each usually keeps the operation of each lease in such a manner that his/her income tax return can be prepared showing each property as a separate operation. The large operator usually has a greater number of control accounts and more detailed subsidiary records.

The acquisition of properties involves such accounts as Producing Royalties, Nonproducing Royalties, Undeveloped Leases Control, and Producing Properties-Leasehold Control. Separate control accounts may be carried for Equipment and Intangible Drilling and Development Costs. Each control account is supported by records.

The subsidiary ledger for nonproducing leases is generally maintained in accordance with geographic location by states, subdivided by counties, with each lease bearing an identification number. This record shows the name of the lease, number of acres covered, legal description, county, state, bonus paid, date of lease, term expiration date, the interest owned, royalty, override, from whom acquired, rental per acre, by whom title examined, other interests, assignments, and rental payment record. This lease record provides a quick and ready reference to any nonproducing property owned without the necessity for consulting the lease file; however, some taxpayers do not maintain a separate lease file.

The total costs of nonproducing properties are recorded in the control account, and a subsidiary record of cost by leases is kept. Some companies make direct charges to the subsidiary nonproducing lease records, while others enter charges in a suspense account for accumulation, and then clear the suspense account by a single entry to the subsidiary lease record.

In order to ascertain that all capital costs are included in the lease record, an analysis of the charges to the lease record or to the suspense account should be made. The items which should appear in these accounts on each lease are the lease bonus, abstract costs, abstract examination fee, filing fee, delay rentals, and travel expense. In addition, there should be charged any commissions paid for obtaining the lease, and any geological and geophysical expense incurred with respect to the area in which such leases were acquired or retained. The cost of a quiet-title suit should also be capitalized.

As leases become productive, the record is transferred to producing lease accounts. The acquisition costs of the underdeveloped leases are transferred to leasehold costs on the producing lease records, to which other costs, capital in nature, in connection with development are added. When a lease terminates without production, the account is transferred to an account for surrendered and expired leases.

Generally, lease bonuses are properly capitalized by the payor. It is quite common to find that other items have not been capitalized by the taxpayer and must be capitalized by the agent during the examination. This requires the close examination of certain accounts and records of expenditures.

Exhibit 4.41.1-5 is a classification of expenditures in acquisition, development, and operation of oil and gas leases.

An investment in minerals may be acquired by cash purchase, exchange of other property, services rendered, gift, inheritance, or liquidating dividends. In any transaction where different properties or assets are acquired, there may be the problem of allocation of the basis to the various properties or assets. In some contracts, the amount involving each separate property or asset may be stated. When stated at realistic values, this eliminates the problem of allocation. Some apparently simple transactions require complex allocations of purchase price to an extent that engineer assistance will be needed.

Frequently promoters, accountants, lawyers, geologists, operators, and others receive an interest in an oil and gas drilling venture in return for services rendered. These services may have been rendered in acquiring drilling prospects; evaluating leases; packaging the drilling program; or, in general, administrative services such as formation of partnerships, filing with Securities and Exchange Commission (SEC), and other functions.

It is a common practice for the promoter or sponsor of a drilling package to acquire part or all of his/her interest in the drilling venture in return for services. G.C.M. 22730, 1941–1 C.B. 214, provided that the receipt of an interest in a drilling venture in return for capital and services furnished by a driller and equipment supplier was not taxable on receipt. This ruling provided for the "pool of capital" doctrine that is widely quoted in oil and gas tax law. The same reasoning has been extended to geologists, petroleum engineers, lease brokers, accountants, and lawyers who receive an interest in an oil or gas drilling venture in return for services rendered. This doctrine resulted from the court decision in Palmer v. Bender , 287 U.S. 551 (1933); 1933–1 C.B. 235; 11 AFTR 1106; 3 USTC 1026.

The "pool of capital doctrine" is widely accepted by accountants and lawyers and is still quoted to justify the tax-free receipt of property for services. Subsequent changes in the tax laws, and subsequent court cases, have significantly limited the use of G.C.M. 22730.

IRC sections 61 and 83, Treas. Reg. 1.61–1(a) and 1.721–1(b) provide that the receipt of property as payment for services rendered is taxable income to the extent of the fair market value of property received. IRC section 83 was enacted by the 1969 Tax Reform Act. IRC section 83 provides rules for the time and manner that property will be valued for this purpose. Case law that supports the taxation of property received for services rendered is James A. Lewis Engineering Inc. v. Commissioner , 339 F.2d 706 (5th Cir. 1964); 15 AFTR 2d 9; 65–1 USTC 9122; Diamond v. Commissioner , 56 T.C. 530 (1971); aff'd, 492 F.2d 286 (7th Cir. 1974); 33 AFTR 2d 852; 74–1 USTC 9309; and U.S. v. Frazell , 335 F.2d 487 (5th Cir. 1964); 14 AFTR 2d 5378; 64–2 USTC 9684; cert. denied, 380 U.S. 961 (1963). But see IRC section 636(a).

Agents who are examining oil and gas partnerships and drilling ventures should carefully analyze the partnership agreement, joint venture agreement, and prospectus to determine if the promoter or sponsor of the venture is receiving a property interest in the form of an interest in a joint venture or partnership in return for services rendered. This is a very complex area of tax law; therefore, it is essential that the facts are carefully analyzed and documented. The issue should not be proposed without extensive research. In most cases, an examiner should discuss the issue with the group manager before attempting to fully develop the issue due to the time usually required by this issue.

An additional problem that will be encountered is that the status of G.C.M. 22730 is unclear at this time. It has not been revoked although it seems to have been partially superseded by the 1954 Code, case law, and the 1969 Tax Reform Act. A request for technical advice would be appropriate when this issue is considered and the adjustment is substantial.

Some guidance with respect to this problem has been issued in Rev. Rul. 83–46, 1983–1 C.B. 16, which holds that an attorney, a corporation, and a corporate employee each have income under IRC section 83 when each receives an overriding royalty in an oil and gas property for services in connection with the acquisition and/or development of the property.Rev. Proc. 93-27 1993-2 C.B. 343 deals with the receipt of a "partnership profits interest " for the provision of services to or for the benefit of a partnership by a person in a partner capacity or in anticipation of being a partner. In certain circumstances the Service will not treat the receipt of such an interest as a taxable event for the partner or partnership. Rev. Proc. 2001-43; 2001-2 C.B. 191 further clarifies Rev. Proc. 93-27. See also Campbell v. Commissioner , 943 F.2d 815 (8th Cir. 1991)

While the pool of capital doctrine is still viable in specific factual circumstances, it does not equate to a special exemption from IRC section 83 for the oil and gas industry. Generally, for the pool of capital doctrine to apply, all of the following must occur:

Drilling contractors will sometimes drill a well on an oil and gas lease in return for an interest in the lease. For instance, if a promoter has acquired a lease on 3,000 acres and lacks the necessary funds to drill a test well, he/she may offer a drilling contractor a 6/8 interest in the lease in return for drilling a well. The drilling contractor will incur 100 percent of the drilling cost in return for a 75 percent interest in the 3,000 acre lease. Since the driller is entitled to only 75 percent of the working interest oil, he/she will be required to capitalize 25 percent of drilling costs and equipment costs as leasehold cost. See Treas. Reg. 1.612–4(a). The promoter can not deduct any cost of drilling or deduct any depreciation because he/she did not incur any expenses.

Oil operators sometime agree to drill a well on another owner's property in return for 100 percent of the working interest in the drilling site. For additional background on this subject, refer to the discussions of " farm-in" and "carried interest" found in IRM 4.41.1.2.3.8 and Rev. Rul. 77–176, 1977–1 C.B. 77.

Rev. Rul. 77–176, 1977–1 C.B. 77, provides examples of the tax treatment to be afforded to the carrying party (operator) and the carried party (lease owner). Generally, the ruling states that the driller will be entitled to deduct 100 percent of the Intangible drilling and development costs (IDC) if the arrangement is a true carried interest. See IRM 4.41.1.2.4.6.4 and references there. The driller will, however, receive income to the extent of the value of the property outside of the drill site. Examiners should carefully inspect the legal instruments and lease assignments where "carried interests" are present to determine if acreage outside of the drilling site is conveyed as consideration of drilling. See Rev. Rul. 77–176, 1977–1 C.B. 77 for instructions.

The "carried party," in situations described above, also incurs a taxable event. The transferor will have a gain or loss on the transfer of property other than the drilling site. The consideration deemed received is the "fair market value" of the property transferred excluding the drilling site.

A net profits interest is considered to be an overriding royalty payable out of the working interest income. See IRC section 614 and Rev. Rul. 73–541, 1973–2 C.B. 206. A conveyance of a drilling site in return for a net profits interest is similar to a situation in which an operator conveys a working interest in a lease and retains an overriding royalty interest. The results would be essentially the same on nonproducing properties. The operator who drills the well would be entitled to deduct 100 percent of the IDC, and the transferor would be considered to have merely retained an overriding royalty interest.

If producing properties are conveyed in exchange for a retained net profits interest, the transferor would generally be subject to the recapture provisions of the tax laws in regard to investment tax credits and depreciation, if a gain results. See IRC sections 50 and 1245

Prior to the Tax Reform Act of 1969, oil and gas production payments were treated as economic interests in oil and gas. In acquisitions of oil and gas leases, production payments were frequently retained by the seller as a financing tool. The purchaser of a lease was not required to report the income accruing to the production payment retained by the previous lease owner. Thus, it can be seen that oil and gas property could be acquired and paid for out of production that was not taxable to the purchaser. A common practice in the acquisition of oil and gas properties was to use a production payment in so-called "ABC" transactions. However, since the 1969 Tax Reform Act, IRC section 636 treats mineral production payments as loans with one exception. Therefore, the acquisition of a property burdened by a production payment is usually similar to the purchase of a property encumbered by a mortgage.

Agents should realize, however, that carved-out production payments pledged for development are excepted from treatment as loans by IRC section 636.

The United States Department of the Interior announces blocks of acreage available for lease by competitive bid under the Outer Continental Shelf Lands Act of a specific date.

Generally, two contiguous leases acquired on the same day, whether by single or separate documents from the same assignor, would be treated as one property [See IRC section 614(j) and Treas. Reg. 1.614–1(a)(3)]. However, government leases are an exception to the rule above (Rev. Rul. 68–566, 1968–2, C.B. 281). The government leases are not considered to be acquired simultaneously, even though executed on the same date, because the granting of any one lease by competitive bidding is independent of the granting on other leases.

Offshore government oil and gas leases may be defined as blocks containing 5,000 acres identified by numbers and includes the seabed and subsoil of the submarine areas adjacent to the territorial waters of the United States over which the United States has exclusive rights, in accordance with international law, with respect to the exploration and exploitation of natural resources.

In many of the Western states of the U.S., the Government owns the mineral rights. These mineral rights are administered by the Bureau of Land Management (BLM) of the Department of the Interior. Except for lands located within a known geologic structure of a producing oil or gas field, BLM is required by law to lease these minerals on a noncompetitive basis to the first qualified applicant. Although some of the minerals are not particularly valuable for oil and gas exploration, some of the minerals are quite attractive.

In an area where there is little or no current oil and gas exploration activity, a person may acquire leases merely by application and paying the filing fees and first year's rental.

The BLM leases the Government tracts which are on proven structures (and are, therefore, not wildcat) to the highest responsible bidder on a competitive bidding basis.

For some years, the competition has been extremely keen for wildcat leases in the attractive areas of New Mexico, Wyoming, and Colorado. Many persons have wanted to be the first qualified applicant when specific tracts become open for leasing. The reason for this is that the leases had a ready market at values many times the amount that BLM will accept for them.

The situation described in paragraph (7) prompted the BLM to devise the following plan for determining who was the first qualified applicant for any tract.

The drawings have all the characteristics of a lottery.

Because of the resemblance to lotteries, it is believed by some people that the successful bidder is actually being awarded a prize and has income to the extent of the difference between the value of the lease and the filing fee. Rev. Rul. 67–135, 1967–1 C.B. 20, settled this question by ruling that the successful applicant has not won a prize and no taxable event has occurred.

Prior to 1956, it had been the Service's position that any cash payment paid by the lessee to the lessor upon granting of an oil and gas lease was a capital investment in the property and not deductible as a business expense. This was true even if the payment was termed a rental and was the same amount for each successive year of the lease. Rev. Rul. 56–252, 1956–1 C.B. 210, superceded by Rev. Rul 80–49, 1980–1 C.B. 127, reversed this position as it applied to Government leases. After the issuance of this revenue ruling (with one exception), all "rentals" paid on Government leases have been treated as business expense, currently deductible.

Rev. Rul. 69–467, 1969–2 C.B. 142, held that, under the following facts, the first-year rentals paid for a Government lease were a capital investment in an overriding royalty.

Fees paid by successful applicants for participation in bidding for noncompetitive Government leases are capital investments. See IRC section 611 and Rev. Rul. 67–141, 1967–1 C.B. 153.

Certain departmental overhead costs should be allocated to the cost of acquiring oil and gas leasehold properties. This includes both developed and undeveloped properties. For a discussion of the various items that should be considered for capitalization in property acquisitions, see IRM 4.41.1.3.2.2(9) and (10).

The use of the terms "farm-in" and " farm-out" are found in connection with the transfer of property in a "sharing arrangement." A "farm-out" and "farm-in" occurs when a leasehold interest in an oil and gas property, along with the burden of developing the property, is transferred from one working interest owner to another and the transferee agrees to assume the development burden in return for the leasehold interest in the property. The transferor will usually retain some type of interest in the property, normally an overriding royalty interest. A farm-out by Taxpayer A, the transferor, is a farm-in to Taxpayer B, the transferee.

The acquisition or disposition of the interest in property by a farm-in or farm-out will not normally result in a taxable event, except for that property which is outside the "drill site" as described in Rev. Rul. 77–176, 1977–1 C.B. 77. See IRM 4.41.1.2.3.3 for the discussion regarding those transfers.

The arrangements and details regarding the transfer of any property should be reviewed in detail to ascertain the taxability of the transaction.

Intangible drilling and development costs (IDC) is a phrase peculiar to the law of oil and gas taxation. It describes all expenditures made for wages, fuel, repairs, hauling, supplies, etc., incident to and necessary for the drilling of wells and the preparation of wells for the production of oil and gas. Treas. Reg. 1.612–4(2) list costs which are specifically designated as costs which come within the option to charge to capital or expense.Treas. Reg. 1.612–5(c)(1) and Rev. Rul. 70–414, 1970–2 C.B. 132, lists costs which are not subject to the option.

IRC section 263(c) provides that intangible drilling and development costs incurred in the development of oil and gas properties may, at the option of the taxpayer, be chargeable to capital or to expense. However, to qualify, the taxpayer must be one who holds a working or operating interest (Treas. Reg. 1.612–4) in the well during the complete payout period. For a definition of "economic interest," see Treas. Reg. 1.611–1(b). For a definition of "operating interest," see Treas. Reg. 1.614–2(b). For a definition of "complete payout period, " see Rev. Rul. 70–336, 1970–1 C.B. 145 and Rev. Rul. 80–109, 1980–1 C.B. 129.

IRC section 263(c) provides that Intangible Drilling and Development Costs (IDC) incurred by an operator in the development of oil and gas properties may, at the taxpayer's option, be chargeable to capital or expense. For this purpose, "operator" is defined as one who holds a working or operating interest in any tract or parcel of land either as a fee owner or under a lease or any other form of contract granting working or operating rights. The option granted by Treas. Reg. 1.612–4 to charge IDC to expense may be exercised by claiming IDC as a deduction on the taxpayer's return for the first taxable year in which the taxpayer pays or incurs such costs. If the taxpayer fails to deduct such costs as expenses on such return, he shall be deemed to have elected to recover such costs through depletion to the extent they are not represented by physical property. The election, once made, is irrevocable. (See Exhibit 4.41.1 - 4).

Taxpayers have the opportunity to make a secondary election to capitalize and amortize, under IRC section 59(e), all or part of the IDC. However, if a taxpayer makes the irrevocable election under IRC section 263(c), this secondary election is not available. A taxpayer may elect to capitalize any portion of the IDC and amortize the cost on a straight line basis over 60 months. The 60 month period is for costs paid or incurred after 1989. The amount subject to the IRC section 59(e) election will not be treated as a tax preference item in determining the taxpayer's Alternative Minimum Tax (ATM).

Exhibit 4.41.1-5 is a classification of expenditures in acquisition, development, and operation of oil and gas leases.

The option with respect to IDC does not apply to expenditures by which the taxpayer acquires tangible property ordinarily considered as having a salvage value. If the taxpayer fails to deduct costs qualifying as intangible drilling costs as expenses on the taxpayer's return for the first taxable year in which the taxpayer pays or incurs such costs, he/she shall be deemed to have elected to recover such costs through depletion to the extent that they are not represented by physical property, and through depreciation to the extent that they are represented by physical property. Normally, taxpayers will elect to deduct IDC currently.

The timing of a tax deduction for many taxpayers is an important factor in the planning of a good tax program. The deductions for IDC could be a major item in this tax planning. Like other deductible expenses, the deductions for IDC depend on the taxpayer making the election to deduct the expenses, method of accounting, drilling contract provisions, and many other factors.

The right to deduct IDC is available only to the taxpayers who own the working interest or operating rights in the properties on which the expenses are incurred. See Treas. Reg. 1.612–4(a). If a well is drilled for the acquisition of a fractional working interest in the property, a deduction for the intangibles is allowed only for the cost attributable to the fractional interest acquired. Any IDC attributable to the working interest owned by someone else is a capital cost and must be added to the leasehold basis of the interest acquired. See Rev. Rul. 70–657 1970–2 C.B. 70.