4.41.1  Oil and Gas Handbook (Cont. 2)

4.41.1.3 
Production and Operation of Oil and Gas Properties

4.41.1.3.9 
Oil and Gas Well Depletion

4.41.1.3.9.2 
Cost Depletion

4.41.1.3.9.2.3 
Appropriate Additional Reserves of Oil and Gas

4.41.1.3.9.2.3.3  (01-01-2005)
Planning and Case Management

  1. Case Management --During the planning phase of the examination, the examiner/engineer should brief management regarding the taxpayer’s compliance with Treas. Reg. section 1.611-2(g)(1). If prior examination histories demonstrate a pattern of the taxpayer disregarding the regulation’s record keeping requirements, the examiner/engineer should seriously consider issuing an Inadequate Record Notice to the taxpayer. If records exist, but the taxpayer will not cooperate in providing information in a timely manner that will assist in the factual development of the reserves issue, the examiner/engineer should obtain appropriate approval to request assistance from Counsel in summonsing the information.

  2. Engineer Involvement --Verifying reserves is within the purview of engineering specialists. Revenue agents should refer all identified cost depletion issues to a petroleum engineer. Mandatory referral criteria are described at http://lmsb.irs.gov/hq/mf/NewHire/JobAids/SRSTA.asp. When cost depletion deductions are significant, the taxpayer will normally have "in-house" engineers or outside consultants prepare the reserve estimates for use by the taxpayer’s accounting department. The taxpayer may use these estimates for full cost accounting financial statements and/or for tax. The RA should obtain copies of these estimates and forward them to the engineer with the request for engineering services.

  3. CAS Involvement -- taxpayer may have hundreds or thousands of properties for which it claims depletion, and the information given to the agent may not be in usable format. In that case, the RA should request a Computer Audit Specialist (CAS) convert the data on tax depletion and/or reserves schedules to a usable format. If a referral to an engineer is necessary, this should be done as early as possible. This will allow the engineer to request these files after consultation with the taxpayer and the CAS as to the best format. Otherwise, there may be delays in the examination.

  4. Information To Be Requested at the Outset of the Examination. The examiner/engineer should request the following information from the taxpayer at the outset of the examination:

    • Detailed tax depletion ledger by tax property, which should include an explanation of the headings. The taxpayer should provide the ledger in hard copy and electronic record format if possible;

    • A reconciliation of the tax return amount to the detailed tax depletion schedule. The taxpayer should provide the reconciliation in hard copy and electronic record format if possible;

    • Detailed reserves and production ledger which shows all reserves, changes to reserves, and annual production by property. Taxpayers may have multiple estimates of reserves (e.g. different categories or different estimates of the same category) and all estimates should be specifically requested. If may be necessary to inquire as to what reserves estimates are maintained by the taxpayer;

    • A reserves handbook or reserves manual that describes how the taxpayer defines all of its different categories of reserves and what reserves the taxpayer considers recoverable;

    • Third party (independent) reserves report(s) prepared for the taxpayer;

    • Separate property election statements; and

    • The accounting manual covering depletion and/or depletion record keeping for the years under examination.

  5. Information To Be Requested on an "As Needed" Basis. The examiner/engineer should request the following on specific properties as needed:

    • Reconciliation of annual lease production (revenue);

    • Reconciliation of leasehold basis and basis additions;

    • Structure and isopach maps;

    • Well logs, well data;

    • Unitization agreements;

    • Lease abandonment report;

    • Like-kind exchange property agreements;

    • Lease sale agreements;

    • Gas contract agreements;

    • Partnership agreements;

    • Appraisal reports performed for the purposes of sales/purchases of properties; and

    • Energy Information Administration (EIA) reports submitted by the taxpayer to the Department of Energy. See IRM 4.41.1.3.9.2.3.1 (7) for further discussion of these reports.

  6. For foreign properties the examiner/engineer should request:

    1. copies of contracts associated with the property, including, but not limited to, exploration, development, production sharing, and risk services agreements;

    2. for properties subject to term renewable contracts the remaining term, contract area, renewable clauses, and current efforts to renew or renegotiate contract;

    3. copy of a current accounting manual covering depletion;

    4. documentation which identifies property units; and

    5. documentation which identifies changes to reserve estimates due solely to economics.

  7. Access to Taxpayer Personnel. The engineer should request the identification and use of the following taxpayer personnel:

    • A person with knowledge of reserve accounting;

    • An engineer with knowledge of all of the taxpayer’s reserve categories associated with specific properties; and

    • A liaison with personal knowledge of the computer system(s) used to compile the data for the taxpayer’s cost depletion file. The computer systems include, but are not limited to, those housing the depletion schedules, recoverable reserve schedules, revenue and expense ledgers, and production data.

  8. Treas. Reg. 1.611-2 provides a list of data that the taxpayer should have readily available to support its depletion deduction.

4.41.1.3.9.2.3.4  (12-03-2013)
Conducting the Reserve Examination

  1. The engineer should understand the source and descriptions of all of the information in the taxpayer’s reserve and depletion ledgers.

  2. After reconciling the tax depletion amount to the tax depletion schedules and receiving any requested information, the engineer should analyze the depletion schedules and select those properties composing the majority of the deduction for an in depth review. Criteria to consider in making a selection of properties for detailed review include (but are not limited to):

    • Properties with high depletion rates. Depletion rate is the fraction or percentage that is multiplied by remaining basis to arrive at cost depletion for the year. Although there are no strict guidelines, many engineers would consider a high depletion rate to be 10 percent for onshore properties, and 20 percent for offshore Gulf of Mexico properties;

    • Properties with material changes in reserve estimates (especially reductions);

    • Properties with material changes in depletion basis (especially deletions to basis);

    • Properties in the first few years of production; and

    • Properties recently farmed out/in, unitized, sold, acquired, or exchanged.

  3. The identity of these properties may have to be requested from the taxpayer via an Information Document Request (IDR). Other sources of information include:

    • Comparative analyses for current and prior cycles;

    • Certain forms attached to the tax return, e.g. Form 4797 (Sales of Business Property) and Form 8824 (like kind Exchanges); or

    • The revisions to reserves that should be available in the taxpayer’s reserves ledgers. The ledgers of many taxpayers incorporate a series of "codes" to identify the nature of any revision to reserves, including those due solely to economics. An explanation of the codes should be obtained.

  4. The engineer should determine what year-end reserves the taxpayer has included in its cost depletion calculation. The reserves might be the same as those submitted to the SEC, or they might be another figure based on company-specific guidelines. In either case the engineer should determine whether the taxpayer excluded any category of proved reserves, such as proved undeveloped or proved non-producing. The engineer should determine how the taxpayer defines, estimates, and compiles its unproved reserves. If it uses the terms "probable" or "prospective" it may not necessarily define them in a manner that is consistent with the regulations. The engineer should also compare them to the SPE petroleum reserves definitions.

  5. The engineer should determine how the taxpayer’s unproved reserves relate to its expected ultimate recovery. Unproved reserves are sometimes presented along with an associated probability of success. Engineers should determine if the quantity of unproved reserves already reflects the probability of success. The engineer may consider analyzing the unproved reserves for each of the selected properties under Treas. Reg. 1.611-2 by referring to the Society of Petroleum Engineers' Probable Reserves Factual Scenarios. See Exhibit 4.41.1-26. If the engineer has any questions while conducting this analysis, the IRS engineer should contact the taxpayer’s reservoir engineer.

  6. After the engineer determines what quantity of unproved reserves should be included in the cost depletion calculation, the engineer should obtain and/or determine the appropriate unproved reserves on a property basis. If the taxpayer determines probable reserves only on the field level, then the engineer should allocate the reserves back to the property level on a proved reserve basis, or other reasonable method. The engineer should then recalculate the cost depletion for each of the selected properties by adding the appropriate unproved reserves to the year-end proved reserves in the denominator of the cost depletion formula.

  7. For foreign properties, there are a variety of unique problems than can affect depletion. There may be issues involving property concepts, term contracts that may or may not have renewal clauses, production sharing agreements, economic/pricing issues, and political constraints. The engineer should consult other engineers with foreign depletion experience if necessary. Refer to North Sea IDC Transition Rule description of some of these contractual arrangements. http://www.irs.gov/Businesses/Petroleum-Industry-Overview-Series---Significant-Law-and-Important-Issues. As with any issue related to a foreign entity, the engineer should consult the international examining agent.

  8. If the engineer has further questions, Petroleum Industry Subject Matter Experts should be contacted.

4.41.1.3.9.2.3.5  (01-01-2005)
Issues Related to Cost Depletion:

  1. In summary, for issues related to cost depletion, examiners should ensure the following:

    • Compute depletion on a property by property basis;

    • Properly allocate basis (including both depreciable and depletable) in the acquisition of multiple properties for a lump sum;

    • Properly match sales (usually production) and estimated reserves for each property. This information is often imported into the depletion ledger from different information systems;

    • Coordinate depletion deductions and abandonment losses so that no amount of basis is deducted twice;

    • Track cumulative depletion for each property so that depletion recapture under IRC 1254 can be properly reported;

    • Conduct a close review of any deletions from depletable basis;

    • Make any additions to depletable basis on the original and not the remaining basis under Rev. Rul. 75-451, 1975-2 CB 330; and

    • Properly follow separate property elections.

4.41.1.3.9.3  (07-31-2002)
Percentage Depletion

  1. 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 4.41.1.3.9.1.3.

  2. Percentage depletion is allowed under IRC 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 613A. This section is quite complex and restrictive and should be studied carefully. Basic and Advanced Oil and Gas Textbooks (Texts 3185–03 and 3186–04) provide a good discussion of IRC 613A. Refiners and retailers (as defined in IRC 613A(d)(2)) are not allowed percentage depletion on oil or hydrocarbon gas, except as provided in IRC 613A(b).

4.41.1.3.9.3.1  (07-31-2002)
Property Unit

  1. The definition of "the property" is very important in the computation of the allowable percentage depletion.

  2. The gross income from the property must include all depletable income to the property for the tax period and may not include income from any other property or source.

  3. Expenses deducted in determining net income and 50 percent (100 percent for taxable years beginning after December 31, 1990) of net taxable income must include all expenses of the property and may not include any negative expenses or other income as offsets against expense of that property.

4.41.1.3.9.3.2  (10-01-2005)
Property Defined

  1. The term "property" means each separate interest owned by the taxpayer in each mineral deposit in each separate tract or parcel of land. Refer to IRC 614(a).

  2. If there is no known mineral deposit under a tract or parcel of land, for property definition it is treated as if it had one deposit.

  3. The definition is very simple. However, its use in practice can become extremely complicated because of its importance and the many and various ways in which property owners, by contract, agree to divide or unitize income and/or operating expenses.

  4. "Separate interest" refers to a type of interest. See Rev. Rul. 77–176, 1977–1 CB 77. The interest may be a working interest, royalty, overriding royalty, production payment, net profits interest, or mineral interest owned in fee.

  5. "Each mineral deposit" refers to minerals in place. See Treas. Reg. 1.611–1(d)(4). With respect to oil and gas wells, each separate mineral deposit refers to each separate subsurface naturally occurring accumulation of oil and/or gas which is separate and apart from and not in naturally occurring communication with any other such accumulation of oil and/or gas.

    • Example 1. Two potential oil productive zones — Devonian and Ellenburger, exist under Tract A, a large undrilled tract of land. There are no other productive zones, and it is not known if either Devonian or Ellenburger zones will produce oil or gas in commercial quantities. Tract A has no mineral deposit.

    • Example 2. The facts are the same as in Example 1 except that a well is drilled on the south side of Tract A to the Devonian, and it now produces oil. Tract A has one mineral deposit.

    • Example 3. Facts are the same as Example 2 except that the well was deepened to the Ellenburger, and that zone now also produces oil. Tract A has two mineral deposits.

    • Example 4. Facts are the same as Example 3 except that an offset to the first well has been drilled, and it produces oil from both Devonian and Ellenburger zones. Tract A has two mineral deposits.

    • Example 5. Facts are the same as Example 4 except that an additional well has been drilled on the north side of the tract, and it also produces from the Devonian and Ellenburger zones. Also, two additional wells have been drilled between the wells on the south side of Tract A and the well on the north side of Tract A. These wells penetrated both Devonian and Ellenburger zones and found them barren of oil. Geological studies now indicate that the wells on the south side and north side are not producing from the same structure, and the mineral deposits are not continuous across the tract. Tract A has four mineral deposits.

  6. "Each separate tract" refers to the physical area and is delineated by legal description; i.e., part of section, section number, block or township and range, survey, county or parish, and state. All contiguous areas, even though separately described, included in a single conveyance or in separate conveyances at the same time from the same owner constitute a single tract or parcel of land. Refer to Rev. Rul. 68–566, 1968–2 CB 281, for contiguous Government leases acquired on the same bid and Examples 8 and 9 of Treas. Reg. 1.614–1 (a), for contiguous leases not originating as a single tract or parcel of land.

  7. The criteria for tax property given previously referred to each mineral deposit. The regulations make it clear that interest in each separate mineral deposit, under a tract or parcel of land, constitutes a separate interest. Although each separate mineral interest is a separate property such separate mineral interests, under the same tract or parcel of land are considered to be "one property" unless the taxpayer elects to treat the separate properties. See Treas. Reg. 1-614-1(a)(3).

  8. In practice the agent has to determine the taxpayer's separate properties. Some taxpayers treat separate "wells" as separate properties. One tax property can have several wells and all the production, income, and expenses needs to be combined to compute depletion for that property. As stated above the computation of percentage depletion is "off book" ; therefore production, income, and expenses can be reallocated by taxpayers to improper properties to maximize the percentage depletion deduction. The taxpayer's "lease files" and AFE's are a good source to determine if misallocations are present.

4.41.1.3.9.3.3  (07-31-2002)
Separate Acquisitions of Contiguous Leases

  1. If contiguous leases are acquired at the same time from different land owners or at different times from the same land owner, the leases constitute separate tracts and, therefore, separate properties. See Treas. Reg. 1.614–1(a)(3).

    Example 1. K. Hayes owns all the minerals in the east half of section 2 (320 acres), and H. Curry owns all the minerals in the west half of the same section 2 (320 acres). Together they meet with C. Dillon on January 13, 1978, and both K. Hayes and H. Curry sign the same oil and gas lease agreement which, in effect, leases all of section 2 to C. Dillon. The agreement is not a unitization agreement within the meaning of Treas. Reg. 1.614–8(b). C. Dillon has two properties.


    Example 2. K. Hayes owns all the minerals in section 2 (640 acres). On January 13, 1978, K. Hayes leases the east half of section 2 for oil and gas to C. Dillon. On May 31, 1978, in a transaction unrelated to the January 13 transaction, K. Hayes leases the west half of section 2 for oil and gas to C. Dillon. Both K. Hayes and C. Dillon have two properties.

4.41.1.3.9.3.4  (07-31-2002)
Acquisition—Additional Working Interest

  1. Each separate acquisition of a working interest in a parcel or tract of land constitutes a separate property.

    Example:

    On January 3, 1978, H. Curry owned one-half and K. Hayes owned one-quarter of the working interest in section 5; C. Dillon owned one-quarter of the working interest in the same section 5. Only one oil deposit is known to underlie section 5. On June 30, 1978, C. Dillon purchased all of H. Curry's working interest in section 5 for $100,000. On December 26, 1978, C. Dillon purchased all of K. Hayes' working interest in section 5 for $100,000. On December 26, 1978, C. Dillon had three properties in section 5.

4.41.1.3.9.3.5  (07-31-2002)
Multiple Producing Zones

  1. Two or more producing zones in one well—each separate producing zone constitutes a separate mineral deposit and, therefore, a separate property.

4.41.1.3.9.3.6  (07-31-2002)
Separate Mineral Interest Election

  1. Notwithstanding the preceding definition of a property, if a taxpayer has two or more operating mineral interests (also known as working interest) located on a tract or parcel of land and wishes to treat them as separate properties, the taxpayer must make an election to treat them separately. Any operating mineral interests located on a single tract or parcel of land for which no separate property treatment election has been made will be combined and treated as one property. See Treas. Reg. 1.614–8(a)(1).

  2. The election described in (e) (1) above must be made by a statement attached to the tax return for the first taxable year beginning after 1963 or the first taxable year in which any expenditure for development or operation, in respect to an operating mineral interest, is made by the taxpayer after acquisition of the interest. See Treas. Reg. 1.614–8(a)(3).

4.41.1.3.9.3.7  (07-31-2002)
Unitizations

  1. If one or more of a taxpayer's operating mineral interests, or a part or parts thereof, participate under a unitization or pooling agreement in a single cooperative or unit plan of operation, then for the period of such participation in taxable years beginning after December 31, 1963, such interests included in such unit shall be treated as one property, separate from the interests not included in such unit. Refer to Treas. Reg. 1.614-8(b)(1).

  2. The term "unitization or pooling agreement" means an agreement under which two or more persons owning operating mineral interests agree to have the interest operated on a unified basis and agree to share in production on a stipulated percentage or fractional basis regardless from which interest the oil or gas is produced. If one person owns several leases, an agreement with royalty owners to determine the royalties payable to each on a stipulated percentage basis regardless from which lease oil or gas is obtained is also a unitization or pooling agreement.

  3. When partially or fully developed leases are unitized for further development and/or secondary recovery operations, there may be equalization payments involved. Some leases which are being unitized may be fully developed with all well sites drilled, while other leases require additional intangible drilling and equipment costs to enter the unit on an equal basis with the fully developed leases. The organizer of the unit (usually the designated unit operator) will normally prepare a schedule of the relative developed condition of each of the leases. This condition is stated in terms of dollar value of equipment and previously expended IDC. A weighted average per drill site is computed for the unit. Each lease is then assigned two values for equipment and intangible drilling costs:

    1. The unit weighted average per drill site multiplied by the number of drill sites on the lease.

    2. The lease's value of equipment and previously expended intangible drilling costs in its condition as the lease enters the unit.

  4. If the value of a lease determined in (b) is greater than the value determined in (a), the owners of that lease will be entitled to receive the dollar value difference. If the value of a lease determined in (b) is less than the value determined in (a), the owners of that lease must pay the dollar value difference.

  5. Payment is usually made by either one of two methods:

    • Cash payments

    • Increase the percentage of revenue to the lease owners due payment and decrease percentage of revenue to the others until equalization has been achieved

  6. The cash payments received are considered as boot in a tax-free exchange of property; IRC sections 1031, 1231, 1245, and 1254 must be considered.

  7. Frequently, the payor of the cash payments will deduct the payments either as IDC (see IRC 263(c)) or as operating expenses (IRC 162(a)). These payments are capital investments in either leasehold or equipment. See Platt v. Commissioner, 18 TC 1229 (1952); aff'd, 207 F.2d 697 (7th Cir. 1953); 44 AFTR 530; 53–2 USTC 48,515. The payment for equipment does not constitute a purchase of used Section 38 property. Refer to Rev. Rul. 74–64 1974–1 CB 12. Therefore, the investment tax credit cannot be claimed by the purchaser.

  8. When possible, the agent should compare the taxpayer's depletion computation schedule for the prior and subsequent years. The addition of a property with the word unit in its name might indicate a current unitization The deletion of one or several properties, which appeared to be making a profit, and the addition of another might indicate a current unitization. Auditing the IDC will show the source of these costs. The agent should study the taxpayer's lease acquisition files and well files to determine each reported property's status. In scanning the depletion schedule, if the agent finds separate leases with the same royalty owner's name, check the effect of combining the computations into one to look at the tax effect. If there is an effect, check lease and well files and/or discuss with the taxpayer to determine property status. If the agent has reason to believe a property has been unitized and it might make a tax difference, a current oil and gas map should be consulted. Frequently, the map company will indicate units on the map by outlining with dashed lines.

4.41.1.3.9.3.8  (07-31-2002)
Percentage Depletion in Case of Oil and Gas Wells

  1. As indicated in IRM 4.41.1.3.9.3.8, subsequent to 1974, no percentage depletion for oil and gas under IRC 613 is allowable except as provided in IRC 613A.

  2. IRC 613A states the conditions under which owners of interests in domestic hydrocarbon oil and gas wells and independent producers and royalty owners are allowed to compute and deduct percentage depletion for oil and/or gas production under IRC 613.

4.41.1.3.9.3.9  (10-01-2005)
Exemption for Certain Domestic Gas Wells

  1. IRC 613A did not affect the computation of percentage depletion for two statutory categories of gas that were prevalent in the mid-1970’s, but which are virtually non-existent today:

    1. Natural gas sold under a fixed price contract, and

    2. Regulated natural gas

4.41.1.3.9.3.10  (12-03-2013)
Depletion Allowable to Independent Producers and Royalty Owners

  1. Except for the 65 percent of taxable income limitation, as provided in IRC 613A(d)(1), a taxpayer who qualifies is allowed to compute and deduct percentage depletion under IRC 613 with respect to a certain amount of average daily production of domestic crude oil and so much of average daily production of domestic natural gas as long as these amounts do not exceed depletable oil and gas quantities. Retailers and refiners, as defined in IRC sections 613A(d)(2) and (4), do not qualify. See paragraphs (10) and (11) below.

  2. For any tax year, a taxpayer's average daily oil production and average daily gas production is determined by dividing total crude oil production and total gas production by the number of days in that tax year. In making this computation, the taxpayer's production of oil and gas resulting from secondary or tertiary processes will not be taken into account. In making this calculation, the taxpayer's production for which depletion is allowable under IRC 613A(b) (gas sold under a fixed contract and regulated natural gas) and production from any proven property transferred after 1974 and before October 12, 1990 will not be taken into account. Refer to IRC 613A(c)(9) for definition of proven property. Before January 1, 1984, secondary and tertiary properties qualify for percentage depletion from proven properties transferred after December 31, 1974.

  3. For any tax year, a taxpayer's depletable gas quantity is 6,000 cubic feet multiplied by the number of barrels of the taxpayer's depletable oil quantity which the taxpayer elects to convert to depletable gas quantity.

  4. Effective January 1,1990 the depletion rate for oil and gas produced by primary, secondary and/or tertiary methods or processes attributable to independent producers and royalty owners is 15 percent.

  5. The tentative quantity specified in IRC 613A(c)(3)(B) is currently 1,000 BBL.

  6. Beginning after December 31, 1990, a 15 percent depletion rate for marginal oil or gas production properties held by independent producers or royalty owners increases by 1 percent (up to a maximum 25 percent rate) for each whole dollar that the reference price for crude oil for the preceding calendar year is less than $20 per barrel. Refer to IRC 613A(c)(6) and Notice 2013-53, 2013-36 IRB 125.

  7. In applying IRC 613A to fiscal-year taxpayers, each portion of such fiscal year which occurs within a single calendar year is treated as if it were a short taxable year. See Treas. Reg. 1.613A–3(k).

  8. For purposes of the depletable oil or gas quantity limitations, component members of a controlled group of corporations, as defined in Treas. Reg. 1.613A–7(1), are treated as one taxpayer. The group shares the one depletable oil or gas quantity. Secondary production of a member of the group will reduce the other members' share of the group's depletable quantity. The depletable oil quantity remaining is then allocated among the entities in proportion to production of barrels of oil and gas (converted to BBL of oil at 6,000 cubic feet = 1 BBL of oil). For purposes of the depletable oil or gas quantity limitation, a family group (which consists of an individual, spouse, and minor children) will be allowed only one tentative oil quantity as shown in IRC 613A(c)(3)(B). The tentative oil quantity is allocated among the individuals in proportion to their respective production of oil and gas (converted to BBL of oil at 6,000 cubic feet =1 BBL of oil).

  9. IRC 613A(c) does not apply to retailers as defined in Treas. Reg. 1.613A–7(r). See IRC 613A(d)(2). A retailer is a taxpayer who directly, or through a related person, sells oil or natural gas or any product derived from oil or natural gas through any retail outlet or outlets; and the combined gross receipts exceed $5,000,000 during the taxable year.

  10. IRC 613A(c) does not apply to refiners as defined in Treas. Reg. 1.613A–7(s). See IRC 613A(d)(4). A person is a refiner if such person or related persons engages in the refining of crude oil and if the total refinery runs of such person and related persons exceed 50,000 barrels on any one day during the taxable year. For taxable years ending after August 8, 2005 the per-day limitation increased to 75,000 barrels and is based on average daily refinery runs. Average daily refinery runs shall be determined by dividing the aggregate refinery runs for the taxable year by the number of days in the taxable year. A refinery run is the volume of inputs of crude oil (excluding any product derived from the oil) into the refining stream.

  11. A taxpayer's total percentage depletion deduction under IRC 613A(d) may not exceed 65 percent of the taxable income for the year, as adjusted. See IRC 613A(d)(1). "As adjusted" means to eliminate the effects of:

    1. Any net operating loss carryback (IRC 172)

    2. Any capital loss carryback (IRC 1212)

    3. In the case of a trust, any distributions to its beneficiaries. For a very limited exception in case of a trust, see Treas. Reg. 1.613A–4(a)(iv). See Exhibit 4.41.1-7 for example. For computation of the 65 percent of taxable income limitation with respect to a corporation entitled to a deduction for dividends received under IRC 243, see IRS Letter Ruling reprint 7902021.

  12. The amount of depletion disallowed in IRC 613A(d)(1) is carried over to succeeding years and treated as an amount allowable as a deduction. Refer to IRC 613A(c) for each succeeding year, subject to the 65 percent limitation of IRC 613A(d)(1). For purposes of adjustment to basis and determining whether cost depletion exceeds percentage depletion with respect to the production from a property, any amount disallowed as a deduction under IRC 613A(d)(1) is allocated to the respective properties in proportion to the percentage depletion otherwise allowable to such properties under IRC 613A(c). After allocation of the amounts disallowed, another comparison of cost depletion and percentage depletion will be made to allow whichever is greater. The amounts disallowed will be carried over to subsequent years. See Exhibit 4.41.1-8 for example.

4.41.1.3.9.4  (10-01-2005)
Lease Bonus

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

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

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

  4. As explained in IRM 4.41.1.3.9.2, the cost depletion formula in Treas. Reg. 1.612–3(a) does not produce a realistic result with respect to a nonproven property. However, in Collums v United States, 480F. Supp. 864, 5, the Court allowed a sublessor to use the computation to deduct 100 percent of basis in a nonproven property as cost depletion. No action or decision has been issued with respect to this case. The case should not be followed unless it becomes apparent that the result in Collums will be accepted by the Service. Such is not the case at this time. See PLR 8532011.

4.41.1.3.9.4.1  (07-31-2002)
Depletion Restoration

  1. If an oil and gas lease on which a bonus has been paid (and depletion was claimed by the lessor) expires or terminates without production, the lessor must restore the depletion claimed to income. See Treas. Reg. 1.612–3(a)(2). However, if a taxpayer has disposed of mineral property subsequent to the receipt of a lease bonus for granting of a lease and prior to the expiration of the lease, the taxpayer is not required to restore to income the depletion previously taken on the bonus. Refer to Rev. Rul. 60–336, 1960–2 CB 195.

  2. If a taxpayer reports an oil and gas lease bonus with respect to a tract of land, the agent should check prior leases on the tract. It may be that depletion taken on a prior lease, which expired in the current year, should be restored to income.

  3. An agent may locate currently expired leases by comparing delay rental receipts from year to year on the books of the taxpayer. Any discontinued delay rentals indicate either a terminated lease and possible restoration of depletion on the bonus or a nonproducing lease that became productive.

  4. On occasion, a lessee may wish to extend an oil and gas lease past its original termination date. This may be done by agreement to extend the lease for a stated period of time, or by the execution of a new lease to take effect immediately on expiration of the old lease. The extension of the old lease or execution of the new lease is commonly called a "top lease." Under these conditions, the Service's position is that the old lease has not terminated. The lessor is not required to restore the depletion taken on the old lease, and the lessee is not allowed to claim an abandonment loss of cost in the old lease. This is true whether the old lease has been "top leased" in whole or in part. If there is a time lapse between the expiration of the old lease and the beginning of the new lease, then there is no "top lease" assuming the delay is arm's-length. For Top Leases, refer to IRM 4.41.1.2.2.3.5.

4.41.1.3.9.5  (10-01-2005)
Partners and Beneficiaries Depletion Deduction

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

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

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

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

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

  6. Examiners should carefully inspect the Form 1041 to ensure that distributions to the beneficiaries are correct and correspond to the amounts reflected on the beneficiaries' returns. It is common practice for a trust instrument to provide a reserve for depletion. Frequently, in such cases a trust or estate will claim depletion on 100 percent of the oil and gas produced and the beneficiary also claims depletion on its share of oil or gas income. The double deduction of depletion should be disallowed. Refer to Treas. Reg. 1.613A–3(f) for guidance.

4.41.1.3.9.6  (07-31-2002)
Valuations of Oil and Gas Producing Properties

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

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

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

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

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

    1. If the value of a property can be determined based on cost or comparative values and replacement value of equipment

    2. If the fair market value can reasonably be determined by any other method. Also see Green v. United States, 460 F.2d 412 (5th Cir. 1972); 29 AFTR 2d 72–1138; 72–1 USTC 84,494.

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

    1. The appraiser project income, expense, and net income on an annual basis

    2. Each year's net income is discounted for interest at the "going rate" to determine the present worth of the future income on an annual and total basis

    3. The total present worth of future income is then discounted further, a percentage based on market conditions, to determine the fair market value. The costs of any expected additional equipment necessary to realize the profits are included in the annual expense, and the proceeds of any expected salvaged of equipment is included in the appropriate annual income.

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

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

4.41.1.3.9.7  (07-31-2002)
Gas Injected for Pressure Maintenance

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

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

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

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

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

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

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

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

4.41.1.3.9.8  (01-01-2005)
Depletion for Geothermal Deposits

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

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

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

4.41.1.4  (01-01-2002)
Sales, Exchanges, and Other Dispositions

  1. This section provides the guidelines for dealing with sales, exchanges, and other dispositions of oil and gas interests.

  2. Frequently, oil and gas interests are transferred to other owners by assignment. The agent will find the major problem to be in the classification of the transaction as a sale, lease, or sublease. The disposition of worthless leases and abandonments will also be covered in this section since they may involve assignments.

  3. The gain or loss resulting from these dispositions will either be deferred by nontaxable exchanges or taxable. Taxable dispositions can be capital gains or losses or ordinary income. The disposition of an interest may trigger IDC and depletion recapture provisions of the Code. In such cases, there may be a problem with classification of the transaction as a sale, lease, or sublease. Proper classification of an assignment is essential to the correct application of the tax laws.

  4. The variety of contract assignments and interests created, transferred, and retained requires a careful reading of the legal documents as a standard examination procedure. A careful interpretation of the contract must be followed by a careful review of the accounting procedures used to record transactions. It should be remembered that the terms of a contract, rather than the intent of the parties, are generally controlling. However, the form of a transaction should not be allowed to take precedence over the real substance of a transaction.

  5. When a lease owner transfers an oil or gas lease to another and receives cash or cash equivalent as consideration, such consideration is either a lease bonus, a sublease bonus, or proceeds from a sale. Therefore, it is important that examiners have a good knowledge of the difference between a leasing (or subleasing) transaction and a sale. If the transferrer retains a nonoperating, continuing interest in the property, then the transaction is a lease or sublease and the cash (or equivalent) received is a bonus. All other such transactions are sales. Refer to IRM 4.41.1.4.2 for a discussion of subleases.

    1. When a lease owner retains a nonoperating interest (royalty, net profits) that entitles the holder to a specified fraction of the total production from the transferred property for the entire economic life of such property, the lease owner has retained a nonoperating, continuing interest in the property.

    2. A nonoperating interest is an economic interest which does not meet the definition of operating interest as defined in Treas. Reg. 1.614–2(b). A royalty, overriding royalty or net profits interest is a nonoperating interest.

4.41.1.4.1  (10-01-2005)
Sale or Lease

  1. The transfer of oil and gas properties may constitute a lease, a sublease, or a sale. The importance of determining whether there is a sale or lease is that the character of the transaction determines the classification of the income to be reported.

  2. If the transfer constitutes a lease, the income received by the lessor is to be reported as ordinary income subject to depletion. If the transaction is a sale, the income may be treated as either ordinary income or capital gain. The agent should be aware that, if a lease is sold and the lease is an inventory item, the proceeds from the sale will be ordinary income. All other income will be either ordinary income, capital gain, IRC 1254, or IRC 1231 gain, depending upon the character of the transaction, the holding period, and whether the recapture of IDC and depletion is required.

  3. An interest in oil and gas in place is an interest in "real property" for federal income tax purposes. Refer to Rev. Rul. 68–226, 1968–1 CB 362. This ruling applies in all cases, regardless of how the oil and gas lessee's interest is treated under state law. An oil and gas lease is subject to IRC 1231 treatment when it is sold; however, such may not be the case when a lease is merely granted or assigned.

  4. When a landowner grants a lease reserving a royalty and receives a cash consideration, the transaction is considered a lease arrangement and not a sale. Refer to Rev. Rul. 69–352, 1969–1 CB 34.

  5. Once the transaction has been determined to be a sale, the agent must determine whether the property is producing or nonproducing. The sale of nonproducing property will usually result in capital gain treatment. The sale of producing property may result in a combination of ordinary income, capital gain, and IRC 1231 gain. As previously stated, mineral leases (developed or undeveloped) are usually real property used in a trade or business. Related lease buildings, equipment, and expenses deducted for tertiary injectants are subject to the recapture provisions of IRC sections 1245 and 1250. IRC 1254 may require the recapture of IDC and depletion as ordinary income. Therefore, except for the recapture provisions, the gain from the sale or exchange of an oil and gas property is treated as capital gain in accordance with IRC 1231. Losses are treated usually as ordinary losses under IRC 1231.

  6. A sale of an interest in oil and gas properties may involve the whole property interest or only a part. Examples of fractional sales are as follows:

    1. An owner may assign an entire interest or a fractional interest.

    2. The owner of a working interest may "carve out" of the working interest and assign any type of continuing nonoperating interest in the property and retain the working interest.

    3. An owner of a continuing property interest may assign that interest and retain a non-continuing interest in production.

  7. Most leases are transferred by either sale, sublease or assignment. However, occasionally there may be a nontaxable exchange. Exchanges of property of like kind held for investment, or for use in a trade or business, may be nontaxable. However, if boot or other consideration is received on the exchange of such properties, the gain is taxable to the extent of the boot received. Refer to IRC 1031 and Treas. Reg. 1.1031(a), (b), and (c).

  8. When a sale of an entire interest in a lease is for cash, the characterization of gain or loss from the sale are simple, as previously discussed in paragraph (2). However, when a fractional interest is sold for cash or for consideration other than cash, a problem may develop in allocating the cash or fair market value of the other consideration between the leasehold and equipment. Since these allocations must be made based on fair market values, they should be made by a petroleum engineer.

  9. If a taxpayer assigns a working interest together with the related lease equipment to another and receives no cash consideration but retains a nonoperating interest (overriding royalty or net profits interest), no deductible loss is allowable. The remaining basis in leasehold and equipment becomes the basis in the interest retained. Refer to Rev. Rul. 70–594, 1970–2 CB 301 and GCM 23623 CB 1943, 313.

  10. The examination techniques used in determining whether a transfer of an oil and gas lease has occurred are the same as in any other industry. One procedure is to look at the balance sheet to determine if leases have been transferred, sold, or abandoned. Once you have determined that a transfer has occurred, look at Schedule D to see if any capital gains have been reported. If the sale cannot be verified, it may be appropriate to ask for a list of the oil and gas properties that have been transferred.

  11. The main examination problem with a lease transfer is determining whether the transfer is a sale or a lease. Obtain a copy of the sale agreement and determine whether the transaction should be classified as a sale, lease, or sublease. Once the transaction is properly classified, the agent can easily apply the correct tax treatment to the transaction.

4.41.1.4.1.1  (10-01-2005)
Sale of Leasehold After Development

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

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

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

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

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

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

    1. Request the property or leasehold ledger.

    2. Determine if all capital expenditures have been added to the cost basis.

    3. Review abandonments to ensure that the taxpayer is not prematurely writing off the leasehold or that the taxpayer is not claiming a deduction for a partial abandonment of a lease.

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

    Initial Cost    
         
    Add:    
         
      Subsequent additions
      IDC — if elected to capitalize
      Attorney fees
      Geological and geophysical costs — if appropriate
      Abstract fees
      Title search costs, etc.
         
    Less:    
         
      Abandonment losses deducted
      Depletion allowed or allowable
      Basis claimed as a return of capital in reporting a sale of a partial interest
      Basis attributable to any portion of the property transferred as a gift, or contribution to corporation or partnership, etc.

  8. The tax treatment of depletion allowed in excess of the basis of a property sold is explained in Rev. Rul. 75–451, 1975–2 CB 330. Generally, gain on the sale or disposition of property on which percentage depletion has exceeded the basis is limited to the selling price. However, the cost of later capital investments in the property must be reduced by the depletion allowed after the adjusted basis was reduced to zero.

    Example:

    The taxpayer purchased mineral property for $1,000,000 and sold it several years later for $500,000. Prior to the sale, the taxpayer's allowable depletion amounted to $1,100,000 (this figure includes any cost depletion and percentage depletion taken). The taxpayer's gain would be $500,000. However, if immediately before the sale, the taxpayer invested $300,000 in depletable property, the gain would be $300,000, the sale price of $500,000 minus the basis of $200,000 ($1,000,000 + $300,000 - $1,100,000 = $200,000).

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

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

    1. For oil and gas property placed in service before 1987, the amount to be recaptured is the amount deducted as IDC after December 31, 1975, reduced by the amount (if any) by which the deduction for depletion under IRC 611 (computed either as provided in IRC 612 or IRC 613A) with respect to the interest that would have been increased if the IDC incurred after 1975 had been charged to capital account rather than deducted. The amount recaptured is limited to: 1) the amount realized, or the fair market value over the adjusted basis of the property, or 2) the IDC as adjusted above, whichever is the smaller amount.

    2. For oil and gas property placed in service after 1986, the amount required to be recaptured is the smaller of the aggregate amount deducted as IDC on the property plus the depletion deductions that reduced the basis of the property or the gain realized on the disposition. No reduction in the amount of IDC required to be recaptured is allowed for the amount by which the depletion deduction would have been increased if the IDC had been capitalized rather than deducted.

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

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

4.41.1.4.1.2  (07-31-2002)
Sale of Lease Equipment

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

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

  3. One problem frequently encountered when depreciable assets are removed from the equipment warehouse and sold is that the taxpayer's book basis may not indicate the correct tax basis. This is due to the customary practice of valuing equipment removed from a lease based upon its condition. This is done in order to pay other owners for their percentage interest. Customarily, the equipment will be placed in the warehouse at the appraised value instead of the adjusted basis. For example, equipment may be valued at 75 percent of the replacement cost if it is in good condition and can be used without additional cost or repairs. The joint owners are paid their share of 75 percent of the new price. Of course, the agent should use the original adjusted basis plus the amount paid to the joint owners as the correct basis for purposes of a sale. See IRM 4.41.1.3.8 for discussion of the treatment of equipment transfers under joint operating agreements.

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

  5. Refer to IRM 4.41.1.2.2.4.2 for further discussion with emphasis on the buyer.

4.41.1.4.1.3  (07-31-2002)
Allocation Between Leasehold and Equipment

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

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

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

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

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

4.41.1.4.1.4  (10-01-2005)
Sale of Fractional Interests in Oil and Gas Leases

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

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

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

    Example:

    The original lessee Taxpayer A has a 7/8 working interest and sells 1/2 of his 7/8 working interest to Taxpayer B. Taxpayer B in turn sells 1/4 of the 1/2 of 7/8 working interest to Taxpayer C. As a result of the sale, Taxpayer A owns 1/2 of 7/8 or .4375, Taxpayer B owns 3/8 of 7/8 or .3281 and Taxpayer C owns 1/8 of 7/8 or .1094. Taxpayer A has 1/2 of the expenses and .4375 of the income; Taxpayer B has 3/8 of the expenses and .328125 of the income; and Taxpayer C has 1/8 of the expenses and .109375 of the income.

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

    Example:

    Taxpayer B leased from Taxpayer A. Taxpayer A retained a 1/8 royalty interest and received a cash bonus of $20,000, from Taxpayer B. Taxpayer B in turn sold 1/2 of the 7/8 working interest to Taxpayer C for $11,500.

    As a result, Taxpayer B would have a capital gain of $1,500 ($11,500 less 1/2 of $20,000). All expenses of production would be shared equally by Taxpayer B and Taxpayer C, and Taxpayer A (the first owner), would report the $20,000 bonus as ordinary income. Any income received by Taxpayer A from the 1/8 royalty would be ordinary income subject to depletion under IRC sections 612, 613 and 613A.

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

    1. In the transfer of the entire working interest in the drill site, neither party will realize income since the pooling of capital concept will apply. Refer to Rev. Rul. 77–176,1977–1 CB 77 and Palmer v. Bender, 287 U.S. 551 (1933).

    2. However, the undivided fraction of the working interest in the remaining tract of land is considered to be compensation to the operator for undertaking the development project on the drill site. The fair market value of the working interest outside of the drill site is included in the gross income of the operator in the earlier of the year the well was completed or when the working interest was received by the operator. The original lessee is considered to have sold the undivided fractional interest for the fair market value on the date of transfer. The nature of the gain or loss will be covered by IRC 1231. Refer to Rev. Rul. 77–176,1977–1 CB 77.

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

    1. If the royalty is held for investment by a nonoperator, gain or loss on a sale will be capital gain or loss.

    2. If the royalty is held for sale in the ordinary course of business by a dealer or broker, gain or loss on its sale is ordinary gain or loss. Refer to Rev. Rul. 73–428, 1973–2 CB 303.

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

4.41.1.4.2  (10-01-2005)
Sublease

  1. A transaction will be classified as a sublease in any case in which the owner of operating rights, or a working interest, assigns all or a portion of those rights to another person and retains a continuing, non-operating interest in production, such as an overriding royalty. Income received in a sublease is ordinary income.

  2. The pivotal point is to determine whether the retained economic interest in the minerals is a non-operating interest such as an overriding royalty.

4.41.1.4.3  (10-01-2005)
Production Payments

  1. Treas. Reg. Section 1.636-3(a) defines the term "production payment" . A production payment is a right to minerals in place that entitles its owner to a specified fraction of production for a limited period of time, or until a specific sum of money or a specific number of units of mineral has been received. A production payment must be an economic interest. It may burden more than property. The characteristic that distinguishes the production payment from an overriding royalty is that the production payment is limited in time, or amount, so that its duration is not co-extensive with the producing life of the property from which it is payable. In other words, the life of the production payment is shorter than the life of the burdened mineral property.

  2. There are two types of production payments. A retained production payment is created when an owner of an interest in a mineral property assigns the interest and retains a production payment, payable out of future production from the property interest assigned. A carved-out production payment is created when an owner of any interest in a mineral property assigns a production payment to another person but retains the interest in the property from which the production payment is assigned.

  3. There are several reasons for the use of production payments.

    1. Production payments are equivalent economically to nonrecourse financing.

    2. Production payments often may be crafted to bridge value perceptions between a buyer and a seller of mineral property.

    3. A seller of property who retains a production payment is permitted to attribute reserves to it for financial statement reporting purposes, thus reducing the reserve reduction suffered by selling producing property.

    4. An owner of a mineral property who carves out a production payment generally retains the tax attributes of the newly burdened mineral property.

4.41.1.4.3.1  (10-01-2005)
Retained Production Payment

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

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

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

4.41.1.4.3.2  (10-01-2005)
Production Payments Pledged for Exploration or Development

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

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

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

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

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

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

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

  8. If existence of a production payment is discovered and appears material, the agent should study the documents that created the production payment to decide its proper treatment. The agent should then check the taxpayer's treatment to see that it is proper.

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

4.41.1.4.3.3  (07-31-2002)
The Ruling Guidelines

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

  2. The conditions are:

    1. The right must be an economic interest in mineral in place without regard to IRC 636;

    2. The right must be limited by a specified dollar amount, a specified quantum of mineral, or a specified period of time;

    3. At the time of creation of the right, it must reasonably be expected that the right will terminate upon the production of not more than 90 percent of the reserves then known to exist; and

    4. The present value of the production expected to remain after the right terminates must be 5 percent or more of the present value of the entire burdened property as of the time the right is created.

4.41.1.4.4  (10-01-2005)
Carried Interest

  1. The term "carried interest" is normally used to define a type of arrangement arising when one party (the "carrier " ) agrees to drill, develop, equip, and operate the working interest owned by another party (the "carried party" ). The carrier agrees to pay the carried party's costs of the property and recover his/her costs out of the carried party's share of the oil and gas produced from the property.

  2. In Herndon Drilling Co. v. Commissioner,, 6 T.C. 628 (1946) the carried party granted the carrying party a fraction of the working interest together with a production payment payable out of the carried party's retained share of the working interest. The life of the production payment was extended for a period necessary for the recoupment of the carried cost by the carrying party. The court held that the carrying party was taxable on all income from the property until payout. The carrying party, on the other hand, could only deduct IDC to the extent of the working interest owned by the carrying party and had to capitalize the excess. The money received as payment for the production payments was income to the carrying party.

  3. In the "Abercrombie" type of carried interest, the carried party assigned a fraction of the working interest and gave a lien on the retained interest to secure development advances made on behalf of the carried party. The carrying party was treated as having made a loan to the carried party to the extent of the carried party's cost of equipment, IDC, and operating expenses (if necessary). The carried party was allowed to treat these costs as if they were paid. As the carrying party recouped these costs from production, the receipts were treated as repayment of loans. This treatment was the result of Commissioner v. J. S. Abercrombie Co., 162 F2d 338, 35 AFTR 1467 (5th Cir. 1947). The Service withdrew its acquiescence (1949-1 CB 1) in 1963–1 CB 5. The Fifth Circuit specifically overruled its decision in Abercrombie in United States v. Cocke, 399 F2d 433, 22 AFTR 2d 5267 (5th Cir. 1968), rev'g 263 F. Supp. 762, 17 AFTR 2d 888 (DC Tex. 1966).

  4. In all of the following revenue rulings, the underlying theory is that the "carrying party" must own the working interest until complete payout to be entitled to deduct all of the IDC. If the carrying party owned 100 percent of the working interest during the payout period, then 100 percent of the IDC may be deducted if a proper election was made.

    1. Rev. Rul. 69–332, 1969–1 CB 87 and Rev. Rul. 71–206, 1971–1 CB 105, deal with the treatment of IDC incurred by a taxpayer who owns less than a full operating interest in an oil and gas well but who is entitled to receive the entire operating interest income until recoupment of all the taxpayer's expenditures.

    2. Rev. Rul. 70–336, 1970–1 CB 145, explains the treatment of IDC by a carrying party whose operating interest is subject to a retained overriding royalty that may be converted to a 50 percent operating interest when cumulated gross production equals a specified amount.

    3. Rev. Rul. 71–207, 1971–1 CB 160, deals with a situation in which the carrying party who owns the entire operating interest in an oil and gas lease until the carrying party has recouped all of the costs of drilling and completing the well, and thereafter, owns an undivided one-half interest.

    4. Rev. Rul. 75–446,1975–2 CB 95, explains the tax treatment of a carrying party who drills and completes an oil and gas well in return for the entire working interest in the lease until 200 percent of the drilling and development plus the equipment and operating costs necessary to produce that amount are recouped, and after such recoupment relinquishes all rights in the interest to the lessee.

  5. If some language of the contract omits or allows the exercise of an option to claim a percentage of the working interest before complete payout, the percentage of IDC deductible by the carrying party is affected. The agent should usually schedule and document the changes in the carried interests because they are a frequent source of tax adjustments.

  6. In order to know all the facts of a carried interest arrangement, the lease assignments, carried interest agreements, operating agreements, and any letter agreements must be studied. These instruments must be studied because of all of the different types of arrangements and provisions used to suit the needs of the taxpayer.

4.41.1.4.4.1  (07-31-2002)
Sale of a Carried Interest

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

    1. The "carried party" who has the right to production to recoup the expenditures of IDC

    2. The "carried party" who possesses the lease interest burdened with the carried interest obligation and will not participate in production until payout has been achieved.

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

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

4.41.1.4.5  (07-31-2002)
Unitization

  1. Unitization occurs when two or more persons owning operating mineral interests agree to have the interests operated on a unitized basis. They further agree to share in production on a stipulated percentage or fractional basis disregarding which lease or interest produces the oil and gas (Treas. Reg. section 1.614–8(b)(6). Unitization may either be voluntary or involuntary. Involuntary unitization may be forced by state conservation laws and regulations. There are various reasons why adjoining property owners unitize their property.

    1. Wells can be placed in the most advantageous location, without regard to lease lines, achieving the most economic development and minimizing operation costs.

    2. The operating problems involved in secondary recovery methods, such as water flooding, are more easily answered by converting some wells to injection wells.

    3. Conservation is aided because the development is fitted to the pools of oil or gas rather than the lease lines.

  2. The Service's position on unitization follows the exchange theory, i.e., a unitization affects an exchange of taxpayer's interest in a smaller property or properties for an undivided interest in the unit. See Rev. Rul. 68–186, 1968–1 CB 354. Under this theory, the formation of a unit falls under the single property provision of IRC 614(b)(3) and constitutes a tax-free exchange of property under the provisions of IRC 1031.

    1. IRC 1031 provides that no gain or loss shall be recognized if property held for productive use in a trade or business is exchanged solely for property of a like kind. Therefore, the exchanges of property interests will be deemed to be exchanges of property of a like kind, even though one property may be developed and the other property undeveloped.

    2. Gain will be recognized only to the extent of any boot received, whether in the form of cash or other property of unlike kind. Loss from such an exchange shall not be recognized. If the property exchanged was held for more than the required holding period, the recognized gain would qualify for capital gain treatment under IRC 1231. However, the taxpayer could realize ordinary gain if the property exchanged qualifies as IRC 1245 property.

    3. Loss from such an exchange is not recognized.

  3. Unitization usually includes not only the mineral interest but also depreciable equipment. Generally, a party to a unitization agreement will have a leasehold cost, which will become the basis for the participating interest in the new unit. If the working interest owner has depreciable equipment, the adjusted basis of the depreciable equipment becomes the basis to his/her interest in the unitized equipment. Boot received upon the unitization exchange is considered to be for a sale of property. Gain must be allocated between the equipment and the leasehold.

  4. Legal fees incurred pertaining to the formation of a unit have been held as deductible expenses and not capital expenditures by the Fifth Circuit Court in Campbell v. Fields, 229 F.2d 197 (5th Cir.1956); 48 AFTR 859; 56–1 USTC 54,470).

4.41.1.4.6  (12-03-2013)
Exchanges of Property

  1. In general, exchanges of oil property are either taxable or nontaxable depending upon the type of properties exchanged. No gain or loss is recognized when property held for productive use in a trade or business, or for investment, is exchanged solely for property of a like kind, which is also held either for productive use in a trade or business or for investment. Since 1975, the "recapture rules" of IRC 1254 may require ordinary income to be recognized in a like kind exchange even if no "boot" or non-like kind property is received. An exchange of "natural resource recapture property" (i.e., mineral property for which IDC or depletion deductions have been taken) for other real property that is not natural resource capture property (e.g., surface fee interest in land) could require IRC 1254 recapture of realized gain.

  2. The nonrecognition rule applies only if the like kind exchange requirements of IRC 1031 are met. Exchanges of property are discussed extensively in Pub 544, Sales and Other Dispositions of Assets. The recapture provision of IRC 1254 is not discussed in the publication, but is covered briefly in the instructions for Form 8824, Like Kind Exchanges. This IRM section should be viewed as complementary to that discussion.

  3. If boot is received on the exchange of property, and assuming that IRC 1254 does not require any recapture, then any gain is recognized only to the extent of the boot received. If property is acquired in a like kind exchange, the basis of that property is generally the same as the basis of the property transferred (that is, carryover basis). Gain or loss that is not recognized in an exchange of property because of IRC 1031 is generally treated as deferred gain.

  4. The exchange of a production payment, which by definition is not a continuing interest in an oil property, for any type of continuing interest in minerals is held by the IRS as a taxable exchange. The IRS also holds that a production payment is not like kind property when compared with continuing interest in real estate. Carved out production payments are generally treated as mortgages and will not qualify in a tax free exchange.

  5. Examples of exchanges of property of like kind are as follows:

    • Producing lease for producing lease (Laster v. Commissioner, 43 BTA 159). It was held that the petitioner exchanged three producing leases for four like assets in a nontaxable exchange.

    • City lot for minerals (Crichton v. Commissioner,122 F.2d 181 (5th Cir. 1941); 27 AFTR 824; 41–2 USTC 808). Mineral rights are interest in real property, so minerals for undivided interest in a city lot was a nontaxable exchange.

    • Ranch land and improvements held for business or investment purposes for working interest (Rev. Rul. 68–331, 1968–1 C.B. 352). "The lessee’s interest in a producing oil lease extending until exhaustion of the deposit is an interest in real property. An exchange of such lease for the fee interest in an improved ranch is a ’like kind’ exchange, except as to the part of the ranch property consisting of a residence, equipment, and livestock."

  6. The following examination techniques may be helpful to examiners in determining if an exchange has occurred:

    • Ask the taxpayer to identify all material exchanges of property. Form 8824 should be completed for each exchange. "Multi-asset exchanges" are very common in the oil and gas industry. As stated in the instruction for Form 8824, if the exchange involved multiple assets, the agent needs to make sure the taxpayer attaches a statement to its return which shows how it determined realized and recognized gain.

    • Review the depreciation schedules for reductions in different classes of assets.

    • On corporation returns, look to Schedule M or M-3 for income not reported for tax.

    • Review the annual reports, news releases, and internet articles for exchanges.

    • Scan the property ledger.

    • Compare oil lease income from one year to another on a property by property basis, giving attention to large changes. Depletion schedules are useful when comparing gross income.

  7. Once the agent determines an exchange has occurred, ask the taxpayer for the journal entries pertaining to the transaction to determine if any "boot" has been passed. A taxpayer might improperly consider a taxable exchange to be a nontaxable exchange and reduce the basis by the boot received instead of recognizing it (to the extent of the gain).

4.41.1.4.6.1  (12-03-2013)
Like Kind Exchange Issues Unique to Oil and Gas

  1. Like kind exchanges are very popular in the oil and gas industry. The key reason is that properties typically have high "built-in gain" due to the current deduction of IDC and/or accelerated depreciation of installed equipment. Issues seen by IRS examiners are discussed below.

  2. Classification of property (e.g., real, tangible personal, intangible). As stated in the introduction to this section, Chief Counsel Advice Memorandum No. 201238027 concluded that federal income tax law rather than state law controls in determining whether exchanged properties are of like kind. The position in the CCA should reduce uncertainty over the treatment of exchanges of pipelines in particular, and it should be closely reviewed by examiners. Examiners should also be aware that a producing oil and gas property will have at least two kinds of property:

    • The mineral rights are an interest in real property.

    • The lease and well equipment is usually tangible personal property.

  3. Inappropriate allocations of fair market value (FMV) for properties exchanged and received. If a difference exists between the allocation of FMV (to minerals and to equipment) for the exchanged properties versus the received properties, some amount of the built-in gain usually has to be recognized. Thus, an issue exists where a taxpayer inappropriately assumes that all producing properties that are part of an exchange (exchanged and/or received) have the same relative percentage of FMV allocable to minerals and equipment. For example, assuming that for each and every property exchanged and received the FMV is comprised of 80 percent minerals and 20 percent equipment is inappropriate unless supported by the facts. Generally, properties that use expensive production equipment tend to have a higher-than-normal portion of their FMV represented by equipment. An IRS engineer may be needed to review the determination of FMV and its allocation.

  4. Example: Property A has FMV of $1000 that is comprised of minerals worth $800 and equipment worth $200. Assume the taxpayer has an adjusted basis of $50 in each for a total of $100. Property A is exchanged for Property B which has a FMV that is comprised of minerals worth $900 and equipment worth $100. Looking at the equipment exchange group, the taxpayer gave up $200 worth of equipment but received only $100 worth of equipment in return. That creates a "deficiency" of $100, which can be viewed as being satisfied by the receipt of $100 of minerals (not of like kind). Gain on the transfer of equipment, computed in accordance with Treas. Reg. 1.1031(j)-1(b)(3)(i) is $150, the difference between the FMV of exchange group property transferred ($200) and its adjusted basis ($50). The amount of gain which must be recognized is $100 which is the lesser of the exchange group deficiency ($100) or the gain on the transfer of the exchange group property ($150). The fact that in the minerals exchange group more value of minerals was received ($900) than was given up ($800) is immaterial.

  5. Example: Property C has FMV of $1000 that is comprised of minerals worth $800 and equipment worth $200. Assume the taxpayer has an adjusted basis of $50 in each for a total of $100. Property C is exchanged for Property D which has a FMV that is comprised of minerals worth $700 and equipment worth $300. Looking at the minerals exchange group, the taxpayer gave up $800 worth of minerals but received only $700 worth of minerals in return. That creates a "deficiency" of $100, which can be viewed as being satisfied by the receipt of $100 in equipment (not of like kind). Gain on the transfer of minerals, computed in accordance with Treas. Reg. 1.1031(j)-1(b)(3)(i), is $750 which is difference between the FMV of exchange group property transferred ($800) and its adjusted basis ($50). The amount of gain which must be recognized is $100 which is the lesser of the exchange group deficiency ($100) or the gain on the transfer of the exchange group property ($750). The fact that in the equipment exchange group more value of equipment was received ($300) than was given up ($200) is immaterial.

  6. The above examples show that an exchange group deficiency exists when the acquired Property B has more or less value in its minerals than Property A. Only when Property B's FMV allocation between minerals and equipment matches Property A's would no exchange group deficiency exist, and therefore no built-in gain would be recognized. Examiners have seen taxpayers use artificially standard allocations of FMV in order to inappropriately defer the recognition of gain that was realized upon the exchange.

4.41.1.4.6.2  (12-03-2013)
Exchanges Involving Natural Resource Recapture Property

  1. IRC 1254 and Treas. Reg. 1.1254-1, Treatment of gain from disposition of natural resource recapture property provides a rule that overrides the nonrecognition provisions of IRC 1031.

    • In general, "natural resource recapture property" is any mineral property for which either IDC (other than for nonproductive wells) or depletion was deducted. An exchange of such property with built-in gain for like kind property that is not natural resource recapture property (such as a fee interest in surface land) results in the realization of gain. The regulation requires gain to be recognized as ordinary income to the extent of "IRC 1254 costs" .

    • Such costs are generally the sum of IDC deducted under IRC 263(c), 59(e), or 291(b) (but not for drilling of nonproductive wells) and depletion deductions which reduced the property's basis (i.e., the percentage depletion claimed after the recovery of basis is not included). See Treas. Reg. 1.1.254-1 for a different formula if the property had been placed in service before 1987.

  2. Treas. Reg. 1.1254-1(b)(3) provides that dispositions do not include certain transactions that are common in the oil industry (e.g., creation of a production payment, lease or sublease and any unitization or pooling arrangement.

  3. Treas. Reg. 1.1254-2(d)(2) provides rules for determination of the amount realized when natural resource recapture property and non-natural resource recapture property are both acquired and disposed of in an exchange or involuntary conversion.

  4. Treas. Reg. 1.1254-3 addresses the treatment of IRC 1254 costs immediately after certain transactions. Generally, when property that is natural resource recapture property is both disposed of and acquired in a like kind exchange or involuntary conversion, an assignment of the IRC 1254 costs of the disposed property is made to the acquired natural resource recapture property. The amount assigned is the IRC 1254 costs of the disposed property minus the amount of ordinary income recognized under IRC 1254(a)(1).

  5. The following example demonstrates the principles of the regulations:

    Example:

    A taxpayer disposes of the following property in a like kind exchange:
    Property A, which is a natural resource recapture property with a fair market value of $1000. Property A has a placed-in-service date of 1991. It has an adjusted basis of $100. Depletion of $300 was taken in computing the adjusted basis. The total amount of intangible drilling and development costs deducted with respect to this property was $200.
    A taxpayer acquires the following property in exchange:
    Property B, a natural resource recapture property with a FMV of $700 and Property C, which is surface land and not a natural resource recapture property. Property C has a FMV of $300.
    The taxpayer's Property A had a built-in gain of $900 which is the difference between the FMV of $1000 and the adjusted basis of $100. Since it was placed-in-service after 1987, its IRC 1254 costs are $500 (depletion of $300 plus IDC of $200). If Property A were sold, the gain recognized would be bifurcated into $500 of ordinary income (IRC 1254 recapture) and $400 of capital gain. However, because it was exchanged for properties that were all like kind, Treas. Reg. 1.1254-2(d)(1) limits the amount to be recaptured under IRC 1254(a)(1) to $300 (the FMV of the surface land, non-natural resource recapture property).
    After the exchange is complete, Treas. Reg. 1.1254-3(d) requires the taxpayer to assign the remaining $200 of IRC 1254 costs ($500 of IRC 1254 costs attributable to disposed Property A minus $300 that the taxpayer recognized as ordinary income) to Property B, the natural resource recapture property acquired. The taxpayer's basis in the two acquired properties (B and C) is $400, the sum of the basis it had in Property A plus the $300 of ordinary income it recognized. Since Property B and Property C are both like kind to Property A, the taxpayer must allocate basis to Properties B and C based on the properties' relative fair market value. Accordingly, 70 percent ($700 divided by $1000) of the $400 is allocated to Property B so that it has $280 basis, equal to $400 multiplied by 70 percent. Similarly, 30 percent ($300 divided by $1000) of the $400 is allocated to Property C so that it has $120 basis, equal to $400 multiplied by 30 percent.

4.41.1.4.7  (07-31-2002)
Capital Gain Versus Ordinary Income

  1. The sale of an entire mineral interest may result in capital gain or ordinary income depending on whether the seller is a dealer or investor.

4.41.1.4.7.1  (07-31-2002)
Seller is a Dealer

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

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

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

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

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

    1. What was the reason, purpose, and intent of the acquisition and ownership of the oil and gas leases during the period they were owned by the taxpayer?

    2. Was there continuity of sales of oil and gas leases over an extended period of time?

    3. Was the amount of income which the plaintiff received from the sales proportionately large in comparison to other income which they received from other businesses?

    4. Did the taxpayer have sufficient assets to develop the oil and gas lease, either by themselves or together with other people, or were they dependent on selling the property in order to make a gain?

    5. Did the taxpayer hold the various properties for long periods of time?

    6. What was the extent of taxpayer's activities in developing the leases or soliciting customers for sale?

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

4.41.1.4.7.1.1  (07-31-2002)
Seller is an Investor

  1. The producer or casual investor will usually buy royalty interests with the hope that oil or gas production will be obtained. If there is production or even good prospects of production, an investor may receive an offer to sell. This sale would qualify for capital gain treatment provided the property was held for the required length of time.

  2. An investor will sometimes trade a fractional interest in a royalty for an interest in another royalty. This type of transaction follows the rule wherein gain realized is recognized only to the extent of the money or unlike property received.

  3. Some techniques to be used in auditing an investor in royalties is to note all credits to the royalty asset accounts and determine their nature. This may reveal a transaction not otherwise shown by a purchase or sale. Accounts in the spouse's name should be examined for items which might represent unreported income. If a loss is shown on the sale of a royalty, determine if there has been any write-off for abandonments, etc., in prior years. Be alert to those situations where a fractional part of an interest is sold. The cost of the entire interest may be shown as the basis for the part sold. Also, remember that any depletion claimed (percentage or cost) must be applied to reduce the basis. A nonproducing property may be under an existing lease for which the taxpayer received a bonus on which depletion was taken. In the termination of the lease, the depletion on the bonus should be restored to income; however, depletion on the bonus is not required when a property is merely transferred. Refer to Rev. Rul. 60–336, 1960–2 CB 195.

4.41.1.4.7.2  (10-01-2005)
Sale of Geological and Geophysical (G&G) Data

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

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

    1. The seismic company acquires G&G data through various means. In some cases, the seismic company will incur all the cost to shoot the seismic and attempt to sell the data to as many interested parties as possible. In other arrangements, the seismic company will organize operators who are interested in certain geographic areas. The seismic data usually is recorded on magnetic tapes.

    2. The Service's position is that the expense to acquire seismic data is a capital expenditure. When the seismic data is inextricably connected to tapes, it is the tapes that are the subject property and various courts have found them to constitute depreciable tangible property. See Texas Instruments, Inc. v. United States, 551 F.2d 599 (5th Cir. 1977) and the dissenting opinion in Sprint Corp. v. Commissioner, 108 T.C. 384 (T.C., 1997). MACRS Asset Class 13.1 (Drilling of Oil and Gas Wells) is appropriate since it includes assets used in the provision of geophysical services. The promulgation of IRC 167(g) restricted the use of the income forecast method of depreciation, and it is not appropriate for seismic data.

4.41.1.4.8  (12-03-2013)
Worthless Minerals

  1. IRC 165 allows a deduction for losses not compensated for by insurance or otherwise if incurred in a trade or business or any transaction entered into for profit though not connected with the taxpayer's trade or business. The losses must be evidenced by a closed and completed transaction or a fixed, identifiable event that establishes that the property has become worthless. The taxpayer must substantiate two facts:

    1. That some event during the taxable year established the worthlessness of the property.

    2. That no event had occurred in a prior year that had established its worthlessness in a prior year. A formal disposition of the interest in the property is not required if worthlessness can be proven by any other means. Refer to Rev. Rul. 54–581, 1954–2 CB 112.

  2. The closed transaction that most clearly establishes worthlessness of oil and gas properties is the relinquishment of title. This can be accomplished by nonpayment of delay rentals, surrender of leases, or a release recorded with a governmental municipality in the appropriate records.

  3. An identifiable event that may prove an oil and gas property worthless is the drilling of a dry hole on or near the property. In each case, it is a question of fact as to whether the dry hole does or does not condemn the property as worthless. Usually, the agent should consult an engineer concerning worthlessness. [See Goodwin v. Commissioner, 9 BTA 1209 (1928); acq., VII-1 CB 12].

  4. A loss deduction is not allowed for shrinkage in value. In Louisiana Land & Exploration Co. v. Commissioner, 7 TC 507 (1946) acq. on other issues, 1946 2 CB 3, aff'd, 161 F.2d 842 (5th Cir. 1947), 35 AFTR 1388, 47-1 USTC 9266, the taxpayer purchased a tract of land for $30,000. The main purpose was to purchase the mineral rights, and the taxpayer allocated $15,000 to mineral rights and $15,000 to surface rights. During the year, the taxpayer's lessee drilled a dry hole and forfeited the lease. The taxpayer retained the ownership in the surface. The court refused to allow the deduction for worthlessness of minerals.

    Note:

    In cases where the mineral and surface rights have separate values for estate purposes, the findings may be different.

  5. In Lyons v. Commissioner, 10 TC 634 (1948), a deduction for partial worthlessness was denied because the taxpayer had several wells on one tract and abandoned some of the wells. The tract was viewed as one unit.

  6. In Gulf Oil Corporation v. Commissioner, 87 T.C. 135 (1986), aff'd, 914 F.2d 396 (3d Cir. 1990), and Phillips Petroleum Co. v. Commissioner, T.C. Memo. 1991-257, the interrelationship between a determination of worthlessness and an overt act of abandonment was addressed at length. These cases should be reviewed closely especially if a taxpayer claims an abandonment loss for any portion of an operating interest while still retaining rights to explore, develop or produce from the property.

  7. IRC 465 generally provides that the amount of loss otherwise allowable with respect to an activity cannot exceed the aggregate amount which a taxpayer has at risk with respect to such activity at the close of the taxable year. Each separate oil and gas property is treated as a separate activity for the purpose of IRC 465. Refer to IRC 465(c)(2)(a)(iv).

4.41.1.4.8.1  (07-31-2002)
Examination Techniques

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

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

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

4.41.1.4.9  (12-03-2013)
Worthless Securities in Oil and Gas Examinations

  1. The deduction for worthless securities under IRC 165(g)(3) is being used by some taxpayers to account for losses for unsuccessful wells. Typically, a controlled foreign corporation (CFC) will be created by a parent corporation or domestic subsidiary to coincide with the acquisition of acreage, which is typically in the form of a "concession" from a foreign country. The costs of acquisition and drilling of the wells within the concession are treated as contributions of capital to the CFC. When the taxpayer determines that the well or wells drilled within the concession are not commercially productive, a decision is made to release the concession back to the foreign government. The parent dissolves the CFC, claims its basis in the stock of the CFC as worthless, and takes an ordinary deduction from income. This deduction is generally a U.S.-sourced loss for the domestic entity.

  2. Treas. Reg. 1.165-1(b) requires that to be allowable as a deduction under IRC 165(a), a loss must be evidenced by closed and completed transactions, fixed by identifiable events. Only a bona fide loss is allowable. Substance and not mere form governs the determination of deductible loss.

  3. Treas. Reg. 1.165-1(d) provides that a loss is allowable under IRC 165(a) only for the taxable year in which the loss is sustained. For this purpose, a loss is treated as sustained during the taxable year in which the loss is evidenced by closed and completed transactions, fixed by identifiable events occurring in the taxable year.

  4. Losses from affiliated corporations, which meet the requirements of IRC 1504(a)(2), may be allowed ordinary treatment instead of capital. In order for worthless securities loss to be considered an ordinary loss, IRC 165(g)(3)(b) requires that more than 90 percent of the gross income of the loss corporation be from non-passive type activities. Taxpayers have taken the position that the ordinary test is met if the corporation has no income, as long as the activity of the corporation is that of an operating company. The Service agreed with that position in a technical advice memorandum (cited as TAM 200914021), concluding that the gross receipts test of IRC 165(g)(3)(B) does not preclude a taxpayer from deducting an ordinary loss for the worthless stock of a wholly-owned operating company that never received any gross receipts.

  5. For further requirements, examiners should review the appropriate issue guidance posted on internal websites, such as foreign joint ventures, foreign partnerships, and check-the-box.

4.41.1.4.9.1  (12-03-2013)
Examination Techniques of Worthless Securities

  1. Examiners should review the criteria for claiming a worthless stock loss and consider whether all of the requirements are met in the year the worthless stock loss is claimed. For example, verify whether the year of release or expiration of the concession coincides with the year of the deduction and whether there was dissolution of the CFC in the year of the deduction or another identifiable event that fixes the loss. Examiners should be aware that a common feature of foreign oil and gas concessions is that they decrease in size as exploration activity delineates the reservoir, but the Service would not allow a deduction for worthlessness as long as the taxpayer retained rights to some portion of the concession. Additionally, examiners should verify that the taxpayer has fulfilled all of its obligations, such as conducting seismic surveys and drilling wells, required by the concession agreements or association agreements.

  2. Examiners should also review the accuracy of the basis computation of the stock in the loss corporation in determining the amount of the loss.

  3. Examiners should be aware that some taxpayers are claiming worthless deductions for stock in newly formed CFCs that acquire tracking interests in operating companies. More specifically, certain taxpayers are:

    • creating a separate CFC for each well from a concession (or grouping wells from different concessions into a single CFC)

    • causing the CFC to acquire tracking stock (or another class of stock) that reflects the performance of a specific well (or specific wells); and

    • claiming a worthlessness deduction for stock in the CFC if the traced wells are not productive.

  4. In considering all of the facts and circumstances with regard to any such worthless stock deduction, review the underlying worthlessness of the property and the economic realities of the structuring (including whether the CFC paid fair market value for the tracking interest). Contact Local Counsel or a Subject Matter Expert for case development suggestions on tracking stock issues.

4.41.1.4.10  (07-31-2002)
Abandonment of Lease

  1. Lease costs usually are deducted from gross income in the year of abandonment. Usually, the year of abandonment will coincide with the year that the property becomes worthless. However, if the situation arises in which the property becomes worthless prior to the overt act of abandonment, the Service considers the year in which worthlessness is established to be the controlling year. "It is held that an abandonment loss is deductible only in the taxable year in which it is actually sustained. An abandonment loss which was actually sustained in a taxable year prior to the year in which the overt act of abandonment took place is not allowed as a deduction in the later year" in Rev. Rul. 54–581, 1954–2 CB 112.

  2. The taxpayer may purchase a large amount of acreage in a single property and later attempt to abandon part of the acreage that is undesirable. This type of abandonment is called a partial abandonment. A partial abandonment loss is not allowable, an abandoned loss can be claimed only when the entire property is abandoned.

  3. The abandonment of nonproducing property has, in fact, occurred when a delay rental payment is not made by the due date. Usually, the loss will be the cost of the property since there should be no deduction claimed for depletion, partial abandonments, etc.

  4. The abandonment of producing properties could be a problem for the examiner. If the property has been producing, the logical question to ask is, "Why does the taxpayer have a loss on abandonment?" Usually, if the reserves have been correctly determined on the property, a taxpayer should have recovered the cost basis by either percentage or cost depletion. Since the taxpayer is entitled to cost depletion, if the lease has run its normal life, the entire cost should have been recovered. Refer to James Petroleum Corp. v. Commissioner, 24 T.C. 509 1955;aff'd 238 F2d 678 (2d Cir. 1956), cert. den. 353 US 910, acq., 1956–1 C.B. 4). However, a property may become unprofitable before the basis is recovered. The examiner must obtain all of the facts.

  5. Expiration under the terms of the lease is considered to be an abandonment if there is no extension of the lease. Under the terms of the lease, the taxpayer may be allowed to operate the lease for a specific time (e.g.10 years) or may have an option to extend the lease for a specific time. The examiner should scrutinize the terms of the lease. If the lease has no options to extend or if the options have not been exercised, the abandonment should be allowed. In allowing an abandonment due to expiration under the terms of the lease, the agent should be aware of the possibilities of top leasing.

4.41.1.4.10.1  (07-31-2002)
Examination Techniques

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

    1. What overt act is evidence of the abandonment? If the taxpayer is claiming an abandonment, there should not be any delay rental deductions in the loss year.

    2. Does the lease expire on a certain date?

    3. Are there any options to renew?

    4. Has the taxpayer canceled the lease, let it expire, or made a new lease on the same property?

    5. Is the taxpayer still paying the taxes on the property he/she is abandoning? Has the taxpayer filed a release in the county records?

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

4.41.1.4.10.2  (07-31-2002)
Forfeit of Lease

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

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

    1. For example, the lease runs July 1 to June 30 of the following year and the taxpayer pays the delay rental for the fiscal year but decides to abandon the lease as of December 31 of the current year. The Service might not allow the deduction until the following year since the delay rental would secure the lease until June 30 of that year.

    2. However, if an event occurred which proved the lease worthless prior to January 1 of the following year, or the taxpayer released the entire lease prior to January 1, examiners should exercise good judgment in considering the December 31 abandonment loss. Generally, delay rentals are not paid on producing leases. Most leases provide that they will remain in effect as long as the lease is producing.

4.41.1.4.10.3  (07-31-2002)
Top Lease

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

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

    1. Comparing new leases against the abandoned leases. Because the new lease probably will not refer to the old lease, the agent will have to compare descriptions and locations.

    2. Asking the taxpayer if there were any top leases. The agent should obtain a legal description of the abandoned leases. The agent should then ask the taxpayer's landman for a current map of the pertinent area showing the taxpayer's current holdings. Top leases should be easily identified when comparing the maps and the legal descriptions.

4.41.1.4.11  (07-31-2002)
Sale of Scrap Equipment

  1. The gain on sale of scrap equipment such as pipes, pumps, and tanks will depend on what the taxpayer means by the term "scrap equipment. "

  2. If the taxpayer defines scrap equipment as a sale of usable equipment that can be used in other oil and gas endeavors, the gain will be considered IRC 1231 gain on the sale of an asset used in a trade or business—subject to IRC 1245 recapture. If the taxpayer is using an ADR method of depreciation, the agent will need to determine if the gain or loss is normal or abnormal. Abnormal (extraordinary) gains or losses for ADR are subject to the tax treatment of IRC sections 1231 and 1245 recapture. Normal retirements resulting in gains or losses will not be reported as income but will affect the asset reserve.

  3. If the taxpayer intends the term "scrap equipment" to mean unidentified equipment and parts not usable in future oil and gas development, sale of scrap equipment is treated as ordinary income.

4.41.1.4.12  (07-31-2002)
Engineering Referrals

  1. When an agent encounters an engineering problem and referral to an engineer is not mandatory under IRM or local directives issued thereunder, the agent may still request the services of an engineer. Discussion with the group manager is appropriate. In many cases, an informal discussion with an engineer can solve the problem. However, when necessary, a referral can be made using the Specialist Referral System (SRS).

  2. Some of the issues an agent may encounter in which an engineer's services would be helpful are listed below:

    • Worthlessness

    • Abandonment

    • Valuations of leasehold and equipment

    • Depletion

  3. Instructions for mandatory referral of oil and gas issues to engineers vary from Territory to Territory. Agents should follow local guidelines.

4.41.1.5  (10-01-2005)
Types of Organizations

  1. This section discusses the many types of organizations in the oil and gas industry.

  2. Many forms of organizational structures can be found in the oil and gas business. An individual may act alone but will normally conduct business as a co-owner with others in a joint venture during the drilling, development, and operations of the oil and gas business. While some taxpayers choose to form Subchapter K partnerships, it is very common for them to form joint ventures which elect out of Subchapter K.

  3. These joint ventures can give rise to certain tax advantages that cannot be achieved in other ownership forms of doing business. This is especially true during the development period of the oil and gas business.

  4. The corporate form of organization is also used to conduct the operations of the oil and gas business. Even though the corporate form of doing business has certain business advantages, there are significant tax disadvantages of using this form to conduct oil and gas operations. The use of the "Subchapter S" corporate form is sometimes used in oil operations, but is not as common because the qualifications for its use are restrictive. It also has some of the tax disadvantages of the regular C corporate form of business.

4.41.1.5.1  (07-31-2002)
Individuals

  1. The tax consequence regarding the cost of drilling and operating oil and gas properties is a very important item an individual takes into consideration before the decision is made to explore and operate oil and gas leases. There are special provisions of the law that recognize these business decisions and give the individuals, co-owners, partnerships, corporations, and other forms of business the elections to deduct currently the cost of what would otherwise be a capital expense. There are other elections the taxpayers can make in order to receive the maximum tax benefits available to oil operators.

4.41.1.5.1.1  (10-01-2005)
Elections

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

4.41.1.5.1.2  (10-01-2005)
Co-Owners

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

4.41.1.5.1.3  (07-31-2002)
Mineral Properties

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

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

4.41.1.5.1.4  (10-01-2005)
Reporting on Tax Return

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

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

4.41.1.5.1.5  (10-01-2005)
Loss Limitations

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

    1. Cash

    2. Adjusted basis of property contributed to the activity

    3. Personal liability for indebtedness

    4. Fair market value of assets outside the activity securing nonrecourse liabilities within the activities.

      Note:

      In addition to the loss limitation provision, the law also provides for a recapture of previously allowed losses when the taxpayer's at-risk amount is reduced below zero. Refer to IRC 465(e).

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

4.41.1.5.2  (12-03-2013)
Partnerships

  1. The partnership has for many years been a favorite vehicle for conducting oil and gas drilling ventures. The popularity of the partnership form in oil and gas ventures is largely due to the flexibility allowed by the partnership code sections. The special allocations of income, gain, loss, deductions or credits (or item thereof) allowed by IRC 704(b), fit the need to share the risk and the financing of oil and gas ventures. Your study of the partnership code section in basic 's school will not be repeated here; however, certain features of partnership law that are of importance in oil and gas partnerships will be discussed.

  2. Examiners should always determine whether the partnership is subject to TEFRA audit rules under IRC 6031(a), which will require an examination at the partnership level in order to make adjustments to partnership items. For example, depletion and IDC have both partnership-level and partner-level components that should be distinguished.

  3. The partnership form of doing business assists oil companies in obtaining financing for oil and gas drilling ventures by permitting unrelated investors to join as partners. Thus, a company is able to finance the drilling costs as well as share the risk in drilling for oil and gas.

  4. The sponsor of an oil and gas drilling partnership may draft a partnership agreement so that most of the Intangible Drilling and Development Costs (IDC) of drilling an oil or gas well may be specially allocated to certain investors, as long as these allocations have substantial economic effect under IRC 704(b). The current tax deduction allowed for IDC, by IRC 263(c), is an incentive to the investors for risking capital in a drilling venture.

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

  6. Nonrecourse financing is sometimes used to increase the amount of deduction for lDC. However, nonrecourse financing generally does not give rise to at-risk basis unless it is secured by the taxpayer’s own property. Accordingly, IRC 465 has generally eliminated the use of nonrecourse financing for individuals after January 1,1976. See IRM 4.41.1.5.2.8 for further information. For qualified nonrecourse financing, refer to IRC 465(b)(6).


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