Oil and gas reservoirs under bays, gulfs, and seas are just like those under land surfaces. Sometimes these reservoirs are extensions of those already proven on shore. Irregularities in subsurface strata exist in such forms as salt plugs or domes, buried reefs, faults, folds, anticlines, or other geologic phenomena related to the shifting of the earth's crust. These irregularities or anomalies may indicate the presence of oil or gas deposits. There must be a source-type rock formation, a reservoir-type rock with pore structure able to contain hydrocarbons, and a barrier-type rock which will trap and retain hydrocarbons migrating from their source bed.

See IRM 4.41.1.2.3.6 with regard to the acquisition of offshore government oil and gas leases.

Income from oil and gas royalties is passive-type income derived from the landowner's royalty, overriding royalty, or a net profits interest. This type of income bears none of the burden of operations or development except taxes. It may be paid by the operator of the property or by the purchaser of the crude oil or gas production. In either event, the royalty owner should receive a statement with the check (usually monthly but at least periodically) showing the total sales of oil and gas from the property, his/her interest in the property, and the amount of production. Taxpayer will normally report royalty income on Schedule "E" as rents and royalties or from flow through entities. The taxpayer can have both royalty and working interest income and report both on a Schedule "C" .

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

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

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

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

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

If the taxpayer assigned all income, he probably still deducted taxes he was liable for.

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

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

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

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

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

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

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

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

If a taxpayer is incurring large intangible development costs on properties to get them to the production stage and then making a practice of transferring them to family members or trusts, it may be that this practice can be attacked under IRC section 183 as not being engaged in business for a profit or under IRC section 482 as an assignment of income.

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

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

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

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

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

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

Since the revenue relating to the production payment may be forwarded directly from the first purchaser of the production to the owner of the production payment, it is difficult to discover the existence of one without special tests being conducted. It is of special importance that the existence of an outstanding production payment be known if the property is sold during the year. The unpaid principal amount of a production payment will constitute additional sales price of the property burdened by the production payment similar to the assumption of a mortgage.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

See Exhibit 4.41.1-9 for items to consider during preparation of Forms 4318, 4764, 4764-Bs, and 886As.

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

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

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

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

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

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

Treas. Reg.1.611–5 provides a reasonable allowance for depreciation of improvements made to oil and gas wells. The deduction allowed under IRC section 611 shall be determined under IRC sections 167 or 168.

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

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

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

In the computation of allowable depreciation using the unit of production method, determination of the proper oil and gas reserves and salvage value is all important in the computation of the correct depreciation allowable.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

There are two resources that may help the examiner identify or discover that a water supply well or salt water disposal well has been drilled. If the taxpayer is an operator, he/she should have an oil field map showing his/her property. All wells should be identified on this map, at least by number. Usually, fresh water wells and salt water disposal wells can be identified from the map. Most state regulatory agencies require a permit to be secured before the well can be staked and drilling started. The operator should have a copy of the application, giving all of the information needed for a determination of the type of well being drilled.

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

There are several other recovery methods in use today. Some of the secondary and tertiary methods being used are:

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

The exception to which we referred in paragraph (1) above applies to "qualified tertiary injectant expenses." For income tax purposes, IRC section 193(a) requires that a taxpayer be allowed as a deduction for the taxable year an amount equal to the qualified tertiary injectant expenses of the tertiary injectants injected during such year. For purposes of IRC section 193, the term "qualified tertiary injectant expenses " means any cost paid or incurred during the taxable year (whether or not chargeable to capital account) for any tertiary injectant (other than a hydrocarbon injectant, which is recoverable) which is used as a part of a tertiary recovery method. The term "hydrocarbon injectant " includes natural gas, crude oil, and any other injectant which is comprised of more than an insignificant amount of natural gas or crude oil. With respect to this deduction, there is no election. A taxpayer is required to take the allowable deduction.

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

A tertiary recovery method is any of the following:

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

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

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

Prior to 11/5/1990, IRC section 29 also required that the price of the gas be regulated under the NGPA. Responding to the phased-in decontrol of wellhead prices under the Natural Gas Wellhead Decontrol Act of 1989, as part of the Omnibus Reconciliation Act of 1990 (OBRA of 1990), Congress removed that requirement. Thereafter, Congress provided that to qualify for the credit, a tight formation well must be on land committed or dedicated to interstate commerce as of April 20, 1977 or must be drilled after the date of enactment of the OBRA (November 5, 1990). See IRC section 29(c)(2)(B).

In Rev. Rul. 90-70 the Service established that for initial completions, the well's spud date will generally be considered as determining the date the well is drilled for purposes of IRC section 29. Rev. Rul. 93-54 holds that for "re-completions" after 1992 from wellbores drilled (spudded) between 12/31/79 and 1/1/93 will qualify as long as the recompletion does not involve deepening the well. The Service’s informal position on recompletions of wells spudded prior to 1980 is reflected in various Private Letter Rulings (PLR's 9025002, 9027005, and 9253050). These PLR’s provide that for recompletions between 12/31/1979 and 1/1/1993 into new qualifying zones, the re-completion date will determine the date "drilled " .

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

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

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

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

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

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

Because many non-conventional fuel producers cannot utilize the full value of their tax credits, they have structured themselves so they have the ability to transfer these credits to other parties. One such arrangement is the direct purchase of the tax credits from the source of production. This is apportioned with respect to allocated interests in the tax credits derived from the production of gas. Under this arrangement, each ownership interest is allocated tax credits according to their participation in the gas produced and the associated tax credits for that year. These tax credits are then entered directly on line 50 of the investor's Form 1040, as described in the Form 1040 instructions. Another strategy has been the royalty trust, where each member of the trust acquires a non-operating net profit interest in the property. Tax credits available for fuel produced on the property are then allocated to the members in proportion to their interest in the royalty trust. There are currently eight publicly traded oil and gas royalty trusts that pass non-conventional fuels tax credits to investors. To some degree it is now possible for an individual to purchase the right to tax credits needed on a yearly basis.

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

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

Discuss the limitations of the AMT with a revenue agent.

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

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

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

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

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

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

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

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

Cost depletion deductions are authorized by IRC sections 611 and 612 and the Regulations issued pursuant to these sections. Prior to January 1, 1975, percentage depletion was authorized by IRC section 613 and the Regulations issued pursuant to this section. Subsequent to January 1, 1975, percentage depletion authorized by IRC section 613, for oil and hydrocarbon gas wells, is substantially limited by IRC section 613A. Those limitations are discussed in IRM 4.41.1.3.5.3, Percentage Depletion. IRC section 613A provides that, for the exceptions listed and under the conditions listed, percentage depletion is allowable under IRC section 613.

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

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

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

If a taxpayer receives a lease bonus on wildcat acreage and claims cost depletion equal to 100 percent of his/her cost, this has the effect of claiming the minerals are worthless as they supposedly will produce no future income. Worthlessness must be proven by an event, and no such event has occurred. Further, it is assumed that the lease itself has value or the lessee would not have paid the bonus. Therefore, cost depletion should not be allowed unless it is possible to make a reasonable estimate of future income and that estimated income is not zero. However, for a contrary decision, see Collums v. United States , 480 F. Supp. 864 AFTR 2d 80–751 (DC Wyo. 1979) with respect to which no action on decision has been issued. See PLR 8532011 and IRM 4.41.1.3.7.4 for additional details on lease bonuses.

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

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

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

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

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