4.41.1 Oil and Gas Handbook

Manual Transmittal

December 03, 2013

Purpose

(1) This transmits revised IRM 4.41.1, Oil and Gas Industry, Oil and Gas Handbook.

Material Changes

(1) Updated Oil and Gas Industry Overview, IRM 4.41.1.1.2 including a description of the oil and gas well drilling industry and international issues. Added Business Segments, downstream and upstream in IRM 4.41.1.1.2.1.

(2) Removed references to Petroleum Industry Program (PIP) as IRM 4.40.4 is obsolete.

(3) Updated Research Material Available in Oil and Gas Taxation in Exhibit 4.41.1-1.

(4) Updated Specialist Referral Procedures in IRM 4.41.1.1.3.

(5) Removed petroleum controlled issues formerly at IRM 4.41.1.1.3.3 in Delegation Orders 4-17 and 4-31 as both were rescinded.

(6) Added IRM 4.41.1.2.2.3.1 Capitalization of Non-direct Costs under IRC 263(c) or IRC 263A; revised IRM 4.41.1.2.2.3.2 Geological and Geophysical Expenditures (G&G); revised Exhibit 4.41.1-5, Classification of Expenditures in Acquisition, Development, and Operation of Oil and Gas Leases; and added Exhibit 4.41.1-6 Rules Regarding Foreign G&G expenditures.

(7) Added IRM 4.41.1.2.4.4 describing distinction between intangible drilling costs (IDC) and nonproductive well costs.

(8) Added new IRM 4.41.1.2.4.5 describing plug and abandonment of wells versus temporary abandonment.

(9) Added new IRM 4.41.1.2.4.8.5, Cash and Carry Arrangements.

(10) Revised IRM 4.41.1.2.4.9 , Offshore Development, Platforms and Drilling Rigs including new content on Subsea Wells, Deepwater Platforms, and examination issues.

(11) Updated court citations in IRM 4.41.1.2.4.9.4, Platform Costs Litigation.

(12) Updated IRM 4.41.1.2.4.9.5, Each Platform Analyzed Separately for Rev. Rul. 89-56.

(13) Clarified IRM 4.41.1.3.1.1 , Income to Royalty Owner.

(14) Revised IRM 4.41.1.3.2.4, Depreciation for unit of production method for wells and added two new sub-sections pertaining to placed-in-service dates for wells and MACRS class life descriptions. Also added new Exhibit 4.41.1-43 providing MACRS asset classes commonly used by taxpayers in the petroleum industry.

(15) Added new IRM 4.41.1.3.2.9,Future Liabilities for Well Plugging, Platform Dismantlement, and Property Restoration.

(16) Updated IRM 4.41.1.3.3.6 providing further guidance on examination of tertiary injectant expenses.

(17) Updated IRM 4.41.1.3.4 Enhanced Oil Recovery Tax Credit to reflect status to issue of strategic value, recently-issued guidance provided through Industry Director Directives and extension of the credit to Alaska gas processing plants.

(18) Added IRM 4.41.1.3.5 IRC 45Q Credit for Sequestration of Carbon Dioxide in Enhanced Oil or Natural Gas Project.

(19) Added IRM 4.41.1.3.7 Marginal Well Credit per IRC 45I.

(20) Updated IRM 4.41.1.3.9.2.1, Depletable Basis.

(21) Revised IRM 4.41.1.3.9.2.2, Reserves of Oil and Gas.

(22) Revised IRM 4.41.1.3.9.2.3, Appropriate Additional Reserves of Oil and Gas and clarifying SEC definitions pertinent to reserves prior to 2010 and post 2009 as Exhibit 4.41.1-45 and Exhibit 4.41.1-46.

(23) Updated IRM 4.41.1.3.9.3.10, Depletion Allowable to Independent Producers and Royalty Owners

(24) Revised IRM 4.41.1.4.6, Exchanges of Property involving Like Kind Exchanges of Oil-Gas Property.

(25) Updated IRM 4.41.1.4.8 , Worthless Minerals with new case decisions.

(26) Added new IRM 4.41.1.4.9, Worthless Securities and Oil and Gas Examinations

(27) Updated income tax provisions for the American Jobs Creation Act of 2004, Energy Policy Act of 2005, Tax Increase Prevention and Reconciliation Act (TIPRA), and the Emergency Economic Stabilization Act to delete reference to IRC 613A. See Exhibit 4.41.1-27, Exhibit 4.41.1-28, Exhibit 4.41.1-29, and Exhibit 4.41.1-30. Deleted expired tax provisions previously numbered as Exhibits 4.41.1-27 Working Families Tax Relief Act and 4.41.1-31 Tax Relief and Health Care Act of 2006.

(28) Updated IRM 4.41.1.5.2, Partnerships.

(29) Added new IRM 4.41.1.5.2.10 describing audit techniques for disguised sale transactions.

(30) Added new IRM 4.41.1.5.3, Publicly Traded Partnerships

(31) Updated IRM 4.41.1.5.4.1, Alternative Minimum Tax Considerations.

(32) Added new IRM 4.41.1.5.4.3, IRC 482 Intercompany Services.

(33) Added new IRM 4.41.1.5.4.4, IRC 199 Domestic Production Deduction

(34) Updated IRM 4.41.1.6, Petroleum Refining, including updated IRM 4.41.1.6.3.1, Allocation of Acquisition Costs, new IRM 4.41.1.6.1.5 Inventory - LIFO and IRM 4.41.1.6.7 Indirect Expenses.

(35) Under IRM 4.41.1.6, Petroleum Refining, added IRM 4.41.1.6.4.4, Line Fill Inventory Issue and new Exhibit 4.41.1-42, Regulatory Agency Filings for Refiners; revised IRM 4.41.1.6.7.3 Refinery Repairs; updated the diagram of the petroleum refining process in Exhibit 4.41.1-14; and added IRM 4.41.1.6.7.4 Turnarounds. Several new tax incentives are described in IRM 4.41.1.6.7.6 Tax Incentives for Refining and Use of Renewable Fuel Incentives: IRC 45H, 179B, 179C, 40A, including a new Exhibit 4.41.1-31 History of IRC 40A, Biodiesel and Renewable Diesel Fuel Credit.

(36) Under Petroleum Refining, added IRM 4.41.1.6.8.2.2, Depreciation for Joint Operations, IRM 4.41.1.6.8.3, Extraordinary and Casualty Losses, revised IRM 4.41.1.6.8.3.4, Fines and Penalties arising from environmental and safety violations. Updated IRM 4.41.1.6.11, Alaska Pipeline Depreciation Treatment of Natural Gas Property, and IRM 4.41.1.6.12, Natural Gas Line Depreciation. Added IRM 4.41.1.6.7.1.2, Depreciation for Precious Metal Catalysts.

(37) Updated and renamed IRM 4.41.1.7.1, Overview of Intercompany Marine Transportation.

(38) Added new IRM 4.41.1.8, Leveraged Oil and Gas Drilling Partnerships (LOGDP).

(39) Added new LOGDP Exhibits in Exhibit 4.41.1-32, Exhibit 4.41.1-33, Exhibit 4.41.1-34, Exhibit 4.41.1-35, Exhibit 4.41.1-36, Exhibit 4.41.1-37, Exhibit 4.41.1-38, Exhibit 4.41.1-39, Exhibit 4.41.1-40, andExhibit 4.41.1-41.

(40) Replaced IRM 4.41.1.9, Definition of Terms Pertaining to the Oil and Gas Industry with Exhibit 4.41.1-44 Glossary of Oil and Gas Industry Terms.

(41) Added IRM 4.41.1.9 Activities and Services Provided on the U.S. Outer Continental Shelf.

(42) Renumbered and updated Exhibit 4.41.1-26, Analysis of SPE Factual Scenarios of Probable Reserves.

(43) Added two new exhibits providing SEC definitions pertinent to oil and gas reserves, Exhibit 4.41.1-45 and Exhibit 4.41.1-46.

Effect on Other Documents

IRM 4.41.1 dated January 28, 2011 is superseded.

Audience

Examination functions in all divisions.

Effective Date

(12-03-2013)

Kathy J. Robbins
Industry Director, Natural Resources and Construction
Large Business and International Division

Overview of Oil and Gas Handbook

  1. This handbook introduces examiners to and assists them in the examination of income tax returns of taxpayers in the oil and gas industry.

  2. Diligent use of these guidelines will shorten the time needed to acquire the examination skills essential to this specialty. Nothing contained herein should discourage examiners from improving upon these techniques or from exercising their own initiative and ingenuity.

  3. Authoritative industry references are available in Exhibit 4.41.1-1 Research Materials, Oil and Gas Taxation. The list is also useful for the study of oil and gas taxation. While the list is not exhaustive, it will provide an excellent introduction.

  4. Refer to Exhibit 4.41.1-10, Items to Consider During Examination for preparing Forms 4318, 4764, 4764-B and 886-A.

Contents and Distribution

  1. These guidelines are a compilation of the examination techniques used by some of our most experienced revenue agents. They are intended to illustrate the variety of problems encountered in examining Federal income tax returns involving oil and gas transactions.

  2. The oil and gas examination guidelines in this handbook identify potential issues and problem areas that an agent will likely encounter in the examination of an oil company or individual operator. While no guideline, examination plan, or textbook can cover all possible issues or examination techniques in an industry as complex and diverse as the petroleum industry, the handbook will be a useful tool for the examiner. However, individual initiative, planning, and research will be needed to cope with the rapid changes taking place within the petroleum industry.

  3. This industry, which involves the exploitation of natural resources, is subject to a large number of substantive tax law provisions. The Internal Revenue Code (IRC) and Regulations have many code sections that deal with the extractive industries. It becomes impractical, if not impossible, to clearly delineate examination techniques from the application of law. In many sections of this IRM, examination techniques are interspersed with discussion of the legal aspects of the particular transactions involved.

  4. References to the tax law will be general and brief in nature and should not be relied upon for complete understanding of the law. Rather, it is recommended that the agent augment these guidelines with research and study. Included in Exhibit 4.41.1-1 is a reference guide to aid research and to supply leads to the major tax law areas concerning the oil and gas industry.

  5. Many examination features in the oil and gas industry are common to commercial enterprises but the handbook will highlight those areas peculiar to the industry.

  6. Note that the examination techniques in this issuance are suggestive but not mandatory procedures for field personnel.

  7. These guidelines do not alter existing technical or procedural examination instructions contained in the IRM. In the event of any inconsistencies between these guidelines and the basic text of the IRM, then the latter will prevail. Procedural statements in this issuance are for emphasis and clarity and are not to be taken as authority for administrative action.

  8. In summary, a good knowledge of oil and gas tax law can only be acquired through study and several years of examination experience in the industry. The examination techniques and procedures presented here are not intended to serve as a textbook in oil and gas tax law. The material presented here should be studied, considered, and applied where appropriate to ensure an efficient and effective examination. It is unlikely that an examiner would ever apply all of the techniques mentioned here in any one examination.

  9. Examiners should consider taking the Micromash course "Oil and Gas Taxation" prior to beginning an examination of an oil and gas company.

Oil and Gas Industry Overview

  1. The oil and gas industry is one of the largest and most important segments of the U.S. economy. Due to the size and complexity of the industry, some basic examination guidelines are needed to assist examiners.

  2. The exploration, development, and production of crude oil and natural gas require enormous amounts of capital. To obtain the funds needed, companies sometimes join together and pool their resources to explore for oil. Large integrated oil companies, as well as small companies and individuals, participate in the exploration, development, and production phases of the oil and gas industry. Many times partnerships are formed to enable outside investors to invest in drilling ventures. The investors may have little knowledge of the oil and gas industry. They are willing to invest funds in risky drilling ventures because the tax benefits are favorable, and large economic benefits are possible. Institutional investors that hope to achieve moderate returns without undue risk are known to invest sizeable amounts in the industry by purchasing royalty interests in producing oil and gas properties.

  3. The transportation, refining, and marketing of petroleum and natural gas by-products, which also require extremely large capital investments, used to be dominated by large vertically integrated oil companies. However, due to a variety of business, economic and regulatory reasons, the number of companies that own all segments of the industry has been greatly reduced. The industry is as active and dynamic as ever, and the large capital requirements still exist, but the complexion has changed markedly. For example, it is fairly common for publicly traded partnerships to own significant portions of midstream and transportation assets.

  4. The importance of the petroleum industry to the economy of the United States has led Congress to pass specialized tax laws that are unique to the oil and gas industry. Petroleum industry accounting records have been adapted to the specialized nature of the industry. As a result, an efficient and effective examination of a return with oil and gas investments, transactions, or operations will require specialized knowledge of the industry, accounting, and tax law.

  5. Oil and gas drillers and service companies make up another large part of the industry. The drilling companies are hired on a contract or fee basis for the drilling rig, labor force, and various other expenses related to the drilling of the well. The fee is often charged on a per-day basis and referred to as a "day rate" . Service companies are hired by oil and gas exploration companies to provide the technology, tools, and expertise throughout the drilling, evaluation, completion, and production phases of the well. Many drillers and service companies are foreign controlled corporations or domestic corporations owning foreign subsidiaries, so referrals to international examiners are often necessary. Some common areas that examiners should be aware of when working these types of companies are:

    1. transfer pricing

    2. research credit

    3. IRC 199

    4. foreign tax credit

Business Segments
  1. At a high level the oil and gas industry is often viewed as having only two primary segments – "Upstream" and "Downstream" . The upstream segment explores for and produces oil and gas that is used by the downstream segment. The downstream segment transports, processes, and refines oil and gas into desirable products and by-products, and then markets them to industrial, wholesale and retail customers. However, it is more appropriate to describe the general activities of these business segments as follows:

    1. Upstream: companies in this segment explore for crude oil and natural gas; develop oil and gas fields; and produce oil and gas via wells. The gathering of those raw products by the producer in the general vicinity of its wells is sometimes considered one of its upstream activities.

    2. Downstream: companies in this segment perform the functions that are not normally considered part of upstream activities. These functions include gathering, processing, transportation, refining, marketing, distribution and retailing. There are some accepted sectors of the downstream segment which are described below, although some functions are performed by more than one. The physical and chemical differences between crude oil and natural gas dictate that the conversion of those raw products into finished ones is typically performed in a different manner (i.e., by different assets, in a different sequence, and in different proximity to the wells).

  2. Generally accepted sectors of the downstream segment are:

    • Midstream and Transportation: companies in this sector perform functions such as gathering crude oil and natural gas from well and field sites; treating natural gas to remove contaminants and to recover natural gas liquids (NGLs); and operating natural gas plants to separate natural gas into "pipeline quality gas" (essentially methane) and other gas and liquid components. These companies also operate "fractionation plants" where large quantities of NGLs are separated into components such as ethane, propane, butane, and iso-butane. Important transportation functions include moving crude oil from gathering sites to oil refineries. Pipelines are normally used; however railcars are occasionally used to move significant quantities of crude oil while a pipeline is under construction. A very extensive network of intrastate and interstate natural gas pipelines transports gas to local utility companies and industrial customers. Companies in this sector also transport refined liquid products from refineries and NGLs and pipeline quality gas from gas plants. Transportation of large quantities is normally done via pipelines, although railcars and river-going barges are used to move some liquid products. Very large ships known as oil tankers and liquefied natural gas (LNG) carriers transport oil and gas between countries and continents.

    • Refining: oil refineries convert crude oil into a wide variety of finished products, such as transportation and heating fuels, lubricants, waxes, asphalts, and petroleum coke. Oil refineries also commonly provide large quantities of hydrocarbon gases and liquids to chemical plants (a.k.a., "petrochemical plants" ) which convert them into plastics, plastic resins, and other products. Oil refineries that process large quantities of "heavy" crude oil may also produce large quantities of elemental sulfur "powder" or "bricks" which can be transported as solids via rail or barge.

    • Marketing and Retail: companies in this sector distribute products like gasoline, diesel, heating oil, and aviation fuel to wholesalers, retailers and end users. While a large percentage of gasoline stations are branded with the name of a well known oil company or refiner, only a minor percentage are actually owned by those corporations. The great majority are franchises. Even with corporate-owned stores, the products they sell may have originated with wells and/or refineries owned by other companies. Over the past few decades the traditional gasoline "service station" has largely been replaced by combination gasoline station and convenience store ("C-stores" ). Natural gas is distributed to residential consumers and to many industrial companies by local gas utility companies.

  3. Service Industry: companies in this segment are primarily known for supporting the upstream segment -- by owning and operating equipment such as drilling rigs; supplying goods such as well casing (pipe); and performing services such as fracturing wells and conducting seismic surveys. Some companies manufacture their own equipment. The scope of these companies range from privately owned firms that operate in a limited region to multinational corporations with activities, employees, and customers around the world.

Requesting Assistance from Specialty Groups and Subject Matter Experts

  1. Petroleum Technical Subject Matter Experts are available for consultation through various Issue Practice Groups and International Practice Networks.

  2. In the course of an examination, the examination will probably require assistance from a specialist. Agents should follow guidelines for mandatory referrals http://lmsb.irs.gov/hq/mf/NewHire/JobAids/SRSTA.asp.

  3. When a specialist is needed, the examiner should involve the specialist early in the examination process. The specialist will greatly assist the examiner in identifying, planning and developing the issues. Referrals to specialists are made on the Specialist Referral System. Refer to IRM 4.60.6.3, Specialist Referral System.http://irm.web.irs.gov/Part4/Chapter60/Section6/IRM4.60.6.asp#4.60.6.3

    1. Engineer Referrals: Referrals should be made during the early stages of each examination when significant and complex engineering issues are noted on the return.

    2. Computer Audit Specialist Referrals: In the course of the examination, the agent should request the assistance of a Computer Audit Specialist (CAS). The CAS should be involved in the review of records for record retention evaluations and to assist the agent as appropriate throughout the examination. The CAS is also trained in the use of statistical sampling techniques. In those instances where the volume of records is such that a 100 percent examination is not feasible, statistical sampling should be considered.

    3. International Examiners: Referrals to International Examiners (IE) are made on the Specialist Referral System during the early stages of each examination initiated when it is ascertained that the taxpayer is engaged in business outside the United States either directly or through related, controlled, or controlling affiliates. See IRM 4.60, International Procedures Manual. Since IRC 482 allocations may be possible in these cases, it is important that the referral reflect all such subsidiaries controlled by the corporation being referred.

    4. Financial Products Specialists: Referrals should be made during the early stages of each examination when significant and complex financial product issues are noted on the return. These may include futures, options, government securities, and other financial products.

    5. Excise and Employment Tax Specialists: During the examination when the agent discovers claims for excise and employment tax payments, the assistance of a specialist should be requested through the team manager.

    6. Tax Exempt and Government Entities (TEGE) Specialists: Contact the agent's manager when complex and extraordinary deductions relating to matters that involve Employee Plans (pension and profit sharing plans), Exempt Organizations, Indian Tribal Governments, Tax Exempt Bonds or Federal State and Local Governments are encountered. The agent's manager must contact the Office of Indian Tribal Governments to coordinate any first contact with an entity owned by an Indian tribal government or situated on Indian land. See http://tege.web.irs.gov/templates/TEGEHome.asp.

Petroleum Industry Statistics

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

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

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

State Regulation of Oil and Gas Production

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

    Example:

    In Texas the Railroad Commission administers the laws relating to oil and gas exploration and production. In Oklahoma it is the Corporation Commission; in Louisiana it is the Office of Conservation.

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

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

Acquisitions

  1. This section provides guidelines for determining the cost of oil producing and non-oil producing property.

  2. First, oil and gas acquisition transactions are described in general.

  3. Second, economic transactions involving oil and gas interests and the tax consequences as they relate to examination techniques are described in detail. See IRM 4.41.1.2.2 and IRM 4.41.1.2.3.

  4. For purposes of this section, the terms "mineral property" or "oil and gas property" refer to a real property interest. A major factor in the examination of oil and gas records is the verification of the cost of a property. The cost (basis) of the real property interest is recovered through depletion. This cost also provides the basis for the computation of gain or loss on the sale of all or part of such property. If the property is producing, the cost or basis of the associated equipment is recovered through depreciation. If the property is nonproducing, the cost may be recoverable upon expiration of the contract or by virtue of its worthlessness demonstrated by unsuccessful development. Refer to Exhibit 4.41.1-3, Useful Examination Techniques - Lease Acquisition Costs.

Acquisition Transactions

  1. The examination of an oil and gas producer (operator) is made difficult by the use of non-uniform accounting procedures. Not only is each taxpayer different but the methods used to record transactions vary. This is because oil and gas producing companies, depending upon their size, keep the type of records they deem sufficient for their needs.

  2. In planning the examination, note whether the return indicates new acquisitions or producing leases. Experience shows that new nonproducing properties are acquired each year, and numerous complications may arise in connection with such acquisitions. A wide variety of problems is created through the various contractual agreements made to acquire and explore oil properties. For this reason, the new properties and the way they are acquired should be closely examined.

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

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

    1. Landowner Interests are those in which the landowner owns the land in fee, including the minerals on and beneath the surface. The landowner may sell or otherwise dispose of subsurface or mineral rights without relinquishing surface rights. Ownership of the mineral rights, which includes the total of all rights to the oil and gas in place, is of primary concern. These rights, separately or jointly held, may include executory rights -- i.e., rights to negotiate, bargain, and sign the oil and gas lease, lease bonus rights, delay rental rights, royalty rights, and operating rights

    2. Non-landowner Interests are those mineral rights held by someone other than the landowner. In this case, the party can sell or otherwise dispose of ownership interest in the minerals. When such dispositions are made, other interests and new owners come into the picture, each having a piece of the mineral deposit. These interests entitle the owners to share in the total production from the property.

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

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

  3. In any subsequent year during the term of the lease, the receipt of the delay rental will be ordinary income to the landowner on which no depletion is allowable. The delay rental is not an advance payment for oil but is in the nature of rent paid for the privilege of deferring development. See Treas. Reg. 1.612–3(c)(2) IRM 4.41.1.2.2.2 Delay Rentals, discusses how the lessee should treat its payment to the landowner.

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

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

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

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

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

    1. Seller's cost included a stipulated amount for mineral rights

    2. Seller's basis was the result of an estate tax valuation in which minerals and surface were valued separately

    3. Seller's cost basis can be properly allocated between surface and minerals because of substantial evidence of value attributable to the minerals at date of acquisition

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

  10. The agent should inspect the prior-year return. The prior-year return may disclose a delay rental which does not appear in the current return. This indicates for the current year either unreported income from delay rental or a lapsed lease which may require restoration of bonus depletion by the lessor.

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

Fee Royalty Owner
  1. The position of a fee royalty owner is the same, irrespective of surface rights ownership. The owner may lease interest, receive a bonus or delay rentals, receive income from production, and may sell all or any portion of royalty interest.

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

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

    2. Working Interest also entitles its owner to share in the production, but this owner must bear its share of the development and operation costs.

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

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

Royalties
  1. The fee royalty generally will represent a negotiated amount between the landowner's retained interest for the oil or gas in place and the lessee oil company. Traditionally, the amount of the fee royalty is 1/8 of the production from the property, however, the amount can vary. Royalty rates of 1/6, 3/16, and 1/4 are also common. Assuming that a 1/8 royalty interest is retained, the remaining 7/8 is generally conveyed as working interest to an operator in consideration for a cash bonus and development of the property. Another type of royalty is known as an override, which is an interest reserved or carved out of the 7/8 working interest, the life of which is coexistent with that of the lease or working interest. Usually the life of the fee royalty is perpetual. However, its life may be limited by the terms of the instrument under which it was created. In some areas, the life of a fee royalty may be governed by state law.

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

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

  3. The small investor may maintain ledger control accounts of producing royalties and nonproducing royalties. These are supported by separate accounting for each property interest (particularly producing properties) and usually showing the property interest owned. The landowner usually has the recorded instruments of conveyance for inspection if they are needed.

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

  5. The royalty dealer usually watches oil company leasing operations very closely. When an area of interest is identified, the dealer begins purchasing the fee royalties in the area. The dealer usually has certain investors with whom it regularly deals, and to whom a portion of the royalty interest is acquired, retaining a small fraction as its own investment. The dealer usually sells a portion of the royalty obtained for a greater sum than the entire cost of the interest obtained. A fraction of the cost corresponding to the fractional interest is retained. Thus, if a dealer purchases 1/16 royalty (1/2 of the landowner's 1/8) for $8,000 and sells a3/64 interest ( 3/4 royalty), the basis for the portion sold is $6,000. The basis of the 1/64 interest retained is $2,000.

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

  7. Amounts paid or incurred for geological and geophysical before enactment of the Energy Tax Incentives Act of 2005 should be capitalized pursuant to Rev. Rul. 83-105. However, amounts paid or incurred for geological and geophysical activity after enactment of the 2005 Energy Bill should be amortized over two years under IRC 167(h). See Exhibit 4.41.1-28. After May 17, 2006, the geological and geophysical amortization amount for certain integrated oil companies was extended to five years. See Exhibit 4.41.1-29.

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

Oil and Gas Leasing Contracts
  1. The interests of an investor or operator in mineral deposits as well as the rights to share in the production from such deposits are governed by the terms of a leasing contract or supporting agreement. Through these contracts there may be numerous assignments, conveyances, and dispositions of interest or rights.

  2. By analyzing the various leasing contracts and the resulting tax consequences, the examiner can pick up leads to potential tax adjustments. A substantial amount of examination time can be spent on such analyses and is often a productive and important examination step.

  3. The oil and gas lease has progressed from a simple instrument to a complex document. Most leases contain eight principal elements:

    1. Principal parties

    2. Date — Determines the precedence of documents.

    3. Habendum clause — Fixes the duration of the lease interest. If production is not attained in the time specified, often called the primary term, the lease expires by its own terms.

    4. Granting clause — Specifies what the lessor has granted and the consideration paid.

    5. Royalty clause — Sets out the principal inducement, aside from the cash consideration, for the property owner to sign the agreement. The landowner's royalty (usually 1/8 of gross production) is free and clear of any drilling or operating expenses.

    6. Drilling and delay rental clauses — One of the primary considerations in an oil and gas lease is the early development of the property. Drilling and delay rental clauses specify the manner in which early drilling can be deferred. This may be done for a specified period by the payment to lessors of delay rentals. However, drilling cannot be deferred past the primary term of the lease without voiding the lease.

    7. Description of the property — An accurate description of the property is necessary. A system of land measurements known as the "Rectangular System" is used today in most oil-producing states. Areas of some oil-producing states, however, are not laid out in this system but are surveyed in parcels, sometimes in irregular geometric patterns.

    8. Special considerations — Additional clauses may be inserted in a lease agreement to more fully describe the rights and duties of the parties; such as, drilling restriction near buildings, right to unitize or pool lands, or right to use surface facilities.

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

Lease and Leasehold Costs

  1. A lease is a contract between a landowner or mineral owner (lessor) and a second party (lessee). The lessor grants to the lessee the exclusive right to drill for and produce oil, gas, or other minerals on the property described in the lease. A lease usually provides for:

    1. Cash (lease bonus) payable to the lessor upon the execution of the lease and approval of the title

    2. Specified term of years, usually from three to ten years

    3. Delay rental for each expiring year during which the lessee has not commenced drilling operations

    4. Lease cancellation if lessee does not pay delay rental by the due date

    5. Basis for division of oil and gas produced between the lessor and the lessee

    6. Continuation of the contract between the lessor and lessee as long as oil or gas is produced from the property

  2. The lessor's share of the production is known as the royalty interest or landowner's royalty. This is usually 1/8 of the oil or gas produced which, by the terms of the lease, is free of all costs of development and operation. The lessee usually acquires 7/8 of the oil or gas produced. This is the working interest and is burdened with the costs of development and operation. The amount of production designated as the landowner's royalty has become fixed by custom. However, in various parts of the United States, 1/5 or 1/6 may be the landowner's royalty, particularly if the landowner is bargaining from a favorable position. In addition, such landowner may be able to obtain a larger lease bonus (in a lump sum or installments). In lieu of a bonus, the lessor and lessee may prefer a minimum (guaranteed) royalty arrangement. This might be the most advantageous position for both parties.

  3. The lessee does not undertake a specific obligation to develop the property or to pay delay rentals, but does agree that the lease will expire if the property is not developed or rentals are not paid. Ordinarily, the lessee can abandon the property without penalty. It is customary, however, for the lessee to formally terminate the lease if the lessee desires to surrender the property without development.

  4. Leases are frequently acquired in what is known as blocks. The usual procedure is for geologists and geophysicists to make certain preliminary surveys of the surface conditions. Core drilling along public highways and other forms of study of the topmost layers of the earth may be indicative of the patterns of folds in the earth's strata at greater depths. If the survey indicates the area is promising for the development of oil or gas, oil company agents acquire leases covering the desired area. Further geological and geophysical work is performed to determine the most favorable portions of the area and whether subsurface structures appear favorable for drilling. Based on this information, certain portions of the acreage may be dropped, and the remainder retained for future development and operation.

  5. In many parts of the country, the mineral or executory rights under a particular tract of land may be owned as an undivided interest by several persons. Each person may lease only the part owned. As a result of this, as many as three or four different operators frequently acquire an undivided interest in the leasehold under a tract of land. An owner of a 1/8 interest in the minerals may sign a lease instrument which is exactly the same as one signed by an owner of 100 percent of the minerals. Thus, the leasing document does not indicate the extent of ownership of the signatory parties. To determine ownership, it may be necessary to study a division order (if property is productive) or an abstract.

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

    1. If it is found that the annual payments are for a fixed number of years regardless of production and if the lessee is unable to avoid such payments by terminating the lease, such annual payments are installment bonus payments and should be capitalized by the lessee as part of the cost of the lease. These payments would be found in the lease rental expense account, but the nature of the payments would be determinable by examination of the provisions of the lease itself.

    2. However, a cash-method taxpayer who receives an installment bonus contract as consideration for an oil or gas lease must include its value in gross income for the year in which the lease is executed if the obligation is transferable and readily saleable. See Rev. Rul. 68–606, 1968–2 CB 42.

    3. A production payment retained in a leasing transaction is treated as bonus paid in installments. See IRC 636(j) and Treas. Reg. 1.636–2(a). The production payment is not taxable when the lease is made by the landowner, only as oil income is received.

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

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

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

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

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

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

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

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

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

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

Capitalization of Non-direct Costs under IRC 263(c) or IRC 263A
  1. "Non-direct" costs generally fall into three broad categories: indirect, overhead, and interest expense. In the oil and gas industry the requirement to capitalize these types of costs is primarily governed by:

    1. IRC 263(a)

    2. IRC 263A - Uniform Capitalization Rules (UNICAP) for Indirect Costs and Interest Expense

    3. Temporary Treas. Reg. 1.263(a)-0T through 1.263(a)-3T, which are known as the "new tangible regulations" are generally effective for taxable years beginning on or after January 1, 2014. Taxpayers may also elect to apply these temporary regulations for taxable years beginning on or after January 1, 2012. See T.D. 9564, Notice 2012-73 and Announcement 2013-7. LB&I Directive dated March 15, 2012 (superseded March 22, 2013) addresses whether an examination of the type of costs covered by the temporary regulations should be conducted, including those for tax years before January 1, 2012. See http://www.irs.gov/Businesses/UPDATEDLBIDIRECTIVEforTPsIRC263a.

  2. IRC 263(a). Intangible Drilling and Developments Costs (IDC) do not draw non-direct costs under UNICAP because of an exception provided in IRC 263A(c)(3). However, IRC 263(c) still requires an allocation of the portion of overhead that is "directly or clearly related" to IDC-type activity. The standard is discussed in PLR 8640006 which cited several court cases. The following excerpts indicate that it is based on facts and circumstances:

    • In the oil and gas industry no uniform pattern of business operations exists and each taxpayer's drilling operations will have to be carefully studied to ascertain the types of overhead expenditures that are directly related to IDC. [T]he portions of general overhead incurred by [a taxpayer] which are clearly related to or identifable with drilling and development activities, are thus properly identifiable and treatable as IDC for purposes of section 263(c) of the Code .

    • Each item of general and administrative overhead must be examined to determine whether it is, in whole or in part, related to the drilling and development activity.

      Example:

      A portion of the rental expense of the headquarters of a small oil and gas company may be incident to and necessary for the drilling and development activity where the headquarters facilitates the coordination of the company's various activities, including drilling.

      Example:

      A substantial portion of the president's salary and related overhead may also be attributed to IDC. The amount of rental expense, which is attributable to IDC, might be determined on the basis of actual floor space devoted to coordination of the company's drilling and development activities.

      Example:

      A portion of the legal fees incurred by an oil company for services provided by an attorney retained by the company is incident to and necessary for the drilling of wells to the extent that these expenditures would be incurred in connection with negotiating and drafting drilling contracts. The amount of legal fees attributable to IDC might be determined on the basis of the proportion of time spent by the attorney in negotiating and drafting the drilling contracts [versus other billable activities].

      Example:

      Also, included in IDC would be the portion of the costs, including overhead of geologists, and field engineers, together with support clerical staff whose major function is to acquire new oil sites and supervise the drilling and development of such sites.

      Example:

      In the event that a relationship is established between an overhead item and both the drilling and development activity and other activities of the taxpayer, such item may appropriately be allocated on some reasonable basis between IDC and other activities.

      Example:

      A major oil company would operate substantially differently from a small independent producer. In that case only the cost related to the departments directly involve with lease acquisition, contract negotiation and drill site development can be attributed to IDC.

    • Since IDC is fully deductible in many circumstances, examiners should perform a risk analysis of switching ordinary expense to IDC, including the impact on AMT liability. The examiner can also ask the taxpayer to identify how much, if any, overhead was added to its direct IDC costs (primarily fees paid to drilling contractors). Companies that serve as the operator of joint ventures routinely charge overhead on IDC to the other working interest owners. A review of Joint Operating Agreements should reveal the level of agreed-upon IDC overhead. If the overhead level for IDC on wells the taxpayer drills on its own account is substantially less, it should be asked to provide an explanation. Generally speaking, even though the amount of overhead is based on facts and circumstance, for most operators it will be at least 5 percent of their direct IDC costs.

  3. IRC 263A. The UNICAP rules generally require taxpayers that produce real property and tangible personal property to capitalize all the direct costs of producing the property and the property's properly allocable share of indirect costs, regardless of whether the property is sold or used in the taxpayer's trade or business. To capitalize means to include costs in the basis of property that is produced or in inventory costs rather than to deduct them as a current expense. The costs are recovered through deductions for depreciation, depletion, amortization, or cost of goods sold when the property is placed in service, sold, or otherwise disposed of.

    1. The regulations under Treas. Reg. 1.263A-1 through 1.263A-6 provide guidance to taxpayers that are required to capitalize certain costs under IRC 263A. These regulations generally apply to all costs required to be capitalized under IRC 263A(a) except for interest. The capitalization of interest is covered under 263A(f) and Treas. Reg. 1.263A-8 through 1.263A-15.

    2. Interest expense is capitalized when real property, such as oil and gas property, is "produced" . The amount of interest expense will depend on an interest rate reflecting an "avoided cost of debt" , the "production period" of the asset, and the cost of the asset. See Treas. Regs. 1.263A-8 through 1.263A-12 in general and 1.263A-13 in particular for oil and gas activities.

    3. Interest expense is also capitalized during the production of personal property that has: MACRS class life of 20 years or more; or, estimated production period of more than two years; or, an estimated production period of more than one year and the estimated cost of production exceeds $1 million.

    4. Companies in the upstream oil and gas sector routinely produce tangible property in the form of wells, separators, tank batteries, and gathering lines which are generally considered personal property since the MACRS class life is only 14 years (Asset class 13.2). Whether interest must be capitalized will depend on the production period and estimated cost. Those items are discussed at length in Treas. Reg. 1.263A-13(b)(1) - (3) and (c)(1) - (7). An extensive review of these regulations is beyond the scope of this IRM.

    5. A similar analysis will be required for assets that are placed into service in such MACRS asset classes as Offshore Drilling (13.0), Drilling of Oil and Gas Wells (13.1), Petroleum Refining (13.3), and Natural Gas Production Plant (49.23) since the class life for each is less than 20 years. On the contrary, since the class life for assets used in Pipeline Transportation (49.21), Gas Utility Distribution Facilities (49.21), Gas Utility Trunk Pipelines and Related Storage Facilities (49.24) and Liquefied Natural Gas Plant (49.25) is 20 years or more, interest expense is capitalized regardless of the estimated production period or estimated cost.

    6. Oil and gas companies in the upstream sector also produce offshore platforms. Whether a "jacket type" platform is an "inherently permanent structure" and should be considered real property for purposes of IRC 263A(f), was addressed in CCA 201211011 (July 1, 2011, transmitting WTA-N-110835-98 (1998)). While a floating deepwater platform is affixed to the seabed in a different manner than a jacket type platform, it has some of the same characteristics. If the taxpayer treated any platform as not being real property for purposes of IRC 263A(f) the examiner should consider contacting Local Counsel or a Subject Matter Expert for IRC 263A.

    7. The total UNICAP costs that have been added to depreciable property that was placed in service during the tax year is to be reported on Line 23 of Form 4562, Depreciation and Amortization. If the amount seems negligible a review of the taxpayer's methodology in arriving at the figure may be warranted.

    8. To determine if the taxpayer is including any UNICAP costs in the basis of its leases, examiners should focus on high cost leases (such as offshore tracts) that recently underwent their initial drilling phase.

      Example:

      Assume that the appropriate "avoided debt" interest rate for a taxpayer is 5 percent. If a lease with a $20 million basis underwent initial drilling for 90 days during the year, then approximately $250,000 of interest expense should have been added to depletable basis [$20 million × 5 percent × (90 ÷ 365 days)] and subtracted from interest expense.

    9. Companies in the natural gas marketing and transportation sectors may acquire gas for resale. Treas. Reg. 1.263A-1 states that IRC 263A does not apply to any costs incurred by a taxpayer relating to natural gas acquired for resale to the extent such costs would otherwise be allocable to cushion gas. Cushion gas is the portion of gas stored in an underground storage facility or reservoir that is required to maintain the level of pressure necessary for operation of the facility. However, IRC 263A applies to costs incurred by a taxpayer relating to natural gas acquired for resale to the extent such costs are properly allocable to emergency gas. Emergency gas is natural gas stored in an underground storage facility or reservoir for use during periods of unusually heavy customer demand. Other gas in the storage facility that is available to meet customer demand (often called "working gas" ) is subject to IRC 263A.

  4. Temporary Regulations for 1.263(a).

    1. Temporary regulations 1.263(a)-0T through 1.263(a)-3T, which are known collectively as the "new tangible regulations" are effective for tax years beginning on or after January 1, 2012. See T.D. 9564. they are set to expire December 23, 2013, but they may be replaced by final regulations on or before that date. LB&I Directive dated March 15, 2012 (superseded March 23, 2013) addresses whether an examination of the type of costs covered by the temporary regulations should be conducted, including those for tax years before January 1, 2012; refer to http://www.irs.gov/Businesses/UPDATEDLBIDIRECTIVEforTPsIRC263a.

    2. The following discussion assumes that an examination of these types of costs is permitted by the aforementioned directive.

    3. Because of the length of the temporary regulations, an exhaustive review will not be provided here; however, three important areas impact the oil and gas industry: whether an amount is paid to acquire or produce a unit of real or personal property (see 1.263(a)-2T); whether an amount is paid to improve a unit of real or personal property, as opposed to repair the unit of property (see 1.263(a)-3T); how to determine an appropriate unit of property (also covered by 1.263(a)-3T).

    4. Examiners will find that the regulations under IRC 263A are referenced throughout the new tangible regulations. For example, 1.263(a)-2T(f)(2)(iv) states that amounts paid for employee compensation (within the meaning of Treas. Reg. 1.263(a)-4(3)(4)(ii)) and overhead are treated as amounts that do not facilitate the acquisition of real or personal property. However, the temporary regulation refers to IRC 263A for the treatment of employee compensation and overhead costs required to be capitalized to property produced by the taxpayer or to property acquired for resale.

    5. Example 4 of 1.263(a)-2T(f)(4) states that although costs paid for geological and geophysical services are inherently facilitative to the acquisition of real property (in the form of an oil and gas lease), taxpayers are not allowed to include those amounts in the basis of the real property acquired. Rather, they must capitalize the geological and geophysical costs separately and amortize them as required under IRC 167(h).

    6. Examiners who focus on refinery improvements and turnaround costs will want to closely review the guidelines for unit of property for "Plant Property" that are found in Treas. Reg. 1.263(a)-3T(e)(3)(ii). they may also want to review Rev. Proc. 2013-24, IRB 2013-22, which provides safe harbor definitions of units of property and major components for steam or electric power generating facilities, to see if useful parallels can be found.

    7. Examiners who focus on pipeline improvements and repairs will want to closely review the statements regarding unit of property for "Network Assets" found in Treas. Reg. 1.263(a)-3T(e)(3)(iii). Agents are encouraged to contact industry subject matter experts for the latest developments in this technical area.

Geological and Geophysical Expenditures
  1. In general geological and geophysical ("G&G" ) expenditures are costs incurred by an oil and gas exploration and production company to obtain, accumulate, and evaluate data that will serve as the basis for the acquisition or retention of oil and gas properties. "G&G" expenditures are usually associated with a survey, such as a seismic, magnetic, or gravity survey conducted by a specialized service company. These expenditures can also include the cost of acquiring well logs and core data, sometimes called "bottom-hole data" , which pertains to wells drilled by other companies.

  2. In recent years the capability of seismic technology has increased dramatically, especially in regards to offshore exploration, drilling and production activities. Data processing and digital imaging have been greatly enhanced by the use of extemely powerful computers and advanced computer modeling techniques. The clarity of seismic surveys has been greatly increased with the advent of "3D" seismic surveys which are achieved by running tightly spaced seismic lines over the entire survey area. In some very large oil fields 3D surveys are conducted periodically (known as "4D" surveys) and evaluated to determine the extent which fluids have moved within the reservoir over time in response to the withdrawal of oil and gas and the injection of water. During drilling operations, sensors that are located in the drill string can collect seismic data "ahead of the drill bit" which can be used to optimize drilling parameters such as mud weight, drill path and casing points.

  3. G&G can be both direct and indirect. An example of a direct cost would be the licensing fee paid to a vendor for the right to use a seismic survey it conducted. Examples of indirect costs would be the salaries of employees who evaluate the survey and overhead of the department which performs the computer processing of the survey. On occasion the evaluation and processing is done by vendors or consultants. Examiners should be aware that for financial accounting purposes such costs are routinely charged to expense. In contrast, for tax purposes, G&G expenditures are generally considered capital expenditures.

  4. G&G expenditures that are charged to current expense should be closely examined. They are frequently charged to "Other Professional Expenses" on Line 26 or may be deducted as intangible drilling costs (IDC). Such accounts should be analyzed for geological and geophysical expenditures.

  5. The tax treatment for domestic G&G expenditures was simplified with the enactment of amortization rules in IRC 167(h). For most oil and gas companies, amounts paid or incurred after August 8, 2005 with respect to domestic properties are amortized over a 24-month period under IRC section 167(h). The half-year convention specified in IRC 167(h)(2) results in the amortization deduction being spread over three tax years.

  6. For certain "major integrated oil companies" defined in IRC 167(h)(5) the amortization period is extended to five years for expenses incurred after May 17, 2006 and seven years for expenses incurred after December 19, 2007. Examiners should note that the definition in IRC 167(h)(5) is unique, and could encompass the foreign refining operations for related entities. For example, a U.S. subsidiary could meet the definition of a major integrated oil company because of its foreign parent corporation’s refining activities, even if the domestic sub doesn’t meet the definition based on its activities. Thus, if a taxpayer amortizes all domestic G&G expenditures over 24 months, an examiner should consider requesting an explanatory statement regarding their classification under the definition. If any questions arise, the examiner should contact Local IRS Counsel.

  7. IRC 167(h)(4) states that if properties are retired or abandoned before the end of the amortization period, amortization of the G&G expenditures continues and no immediate deduction is allowed for remaining amortizable amounts.

  8. However, G&G expenditures incurred with respect to foreign properties are not subject to the amortization rules; such costs must be capitalized. The tax treatment of foreign G&G expenditures is discussed in Rev. Rul. 77-188, 1977-1 C.B. 76 as amplified by Rev. Rul. 83-105, 1983-2 C.B. 51. The assistance of an engineer will generally be needed in the examination of these expenditures. See Exhibit 4.41.1-6 for a detailed discussion of the rules regarding foreign geological and geophysical expenditures.

  9. Examiners may find that G&G expenditures are sometimes deducted as Intangible Drilling Costs (IDC). The definition of IDC in Treas. Reg. 1.612-4 does encompass certain "geologic works" . See Exhibit 4.41.1-5 where they are defined as "survey and seismic costs to locate a well site on leased property" . Often, taxpayers will deduct an entire G&G survey as IDC when only a small portion relates to a specific well location. An IRS engineer may have to be consulted if that situation arises. There is no published guidance on whether the amortization rule of IRC 167(h) supersedes the deduction of "well-site G&G" as IDC. The examiner should contact Local IRS Counsel if this is a material issue.

Legal, Travel, and Other Expenses
  1. Legal expenses should be examined for charges for examination of abstracts, filing fees, quiet-title suits, and other items which should be capitalized as lease costs. General office expense or sundry expense accounts will often reveal charges applicable to lease acquisition costs.

  2. Expenditures for travel incurred in the acquisition of leases must be capitalized and allocated to the leases involved. Analyze travel and other expenditures to determine those relative to the individuals instrumental in acquiring leases. Then relate these expenditures to leases comparing the locations and times of travel with the dates the leases were acquired.

Minimum Royalty and Advance Royalty Payments
  1. The original mineral owner (lessor) or a sublessor may contract for an advance royalty on transfer of the operating interest. Advance royalties result from lease provisions that require the operating interest owner to pay a specified royalty (a fixed amount or an amount based on royalties due on a specified production level) regardless of whether there is any oil or gas extracted within the period for which the royalty is due. Advance royalties also allow the lessee to apply any amount paid on account of oil and gas not extracted against royalties due on production in subsequent periods.

    Example:

    A lease with a primary term of 10 years requires a 1/8 production royalty and also requires that royalties of $100,000 be paid at the beginning of each of the first three years. If, in the first lease year the production royalties are $20,000, the advanced royalty is $80,000.

  2. Generally, the payor of an advanced royalty can deduct the advanced royalty from gross income for the year in which the oil or gas on account of which it was paid is sold. See Treas. Reg. 1.612–3(b)(3). However, advanced royalties that result from a minimum royalty provision may, at the option of the payor, be deducted in the year paid or accrued.

  3. For leases entered prior to October 29, 1976, this option to deduct in the year paid or accrued was available for all advance royalties. The option, however, is a one-time election for the taxpayer and, once chosen, cannot be changed.

  4. A minimum royalty provision requires that a substantially uniform amount of royalties be paid at least annually either over the life of the lease or for a period of at least 20 years in the absence of mineral production requiring payment of aggregate royalties in a greater amount. The example in paragraph (1) above is not a minimum royalty. See Treas. Reg. 1.612–3(b)(3).

  5. Depletion is generally allowable in the year the oil or gas is produced under IRC 613A. However, the Supreme Court decided in the consolidated cases of Fred L. Engle and Phillip D. Farmar dated January 10, 1984, that percentage depletion is allowable on oil and gas lease bonuses and advance royalty income. See Commissioner v. Engle, 464 US 206 (1984). The IRS stated in a news release dated May 18, 1984, that the depletion deduction could be taken in the year payment is received or accrued by the payee. Refer to Announcement 84-59,1984-23 IRB 58. Refer to IRM 4.41.1.3.9.3 for additional discussion of percentage depletion.

  6. Examination of the lease record (which would include the royalty agreement), the journal entries recording minimum royalty transactions, and the related ledger accounts are proper steps to verify these transactions.

Top Leasing
  1. If a lease expires, any capitalized cost of the lease becomes a loss, even though the taxpayer may subsequently obtain a new lease on the property. If, prior to the expiration of a lease, a new lease is obtained covering the property, it is known as a top lease. In this case, the cost of the prior lease should not be allowed as a loss; and any bonus and other costs incurred in obtaining the renewal lease should be capitalized. In such event, the costs of both the old and new leases are included in the capital account of the property.

  2. During the examination, look for top leasing transactions. Taxpayers frequently write off the cost of the original lease. Leases are carried under an identification number. The renewal may be noted by an "R" immediately after the lease number. Otherwise, compare the leases claimed as expirations with the new leases to see if the same property is involved. Another method is to ask the taxpayer if there are any top leases. Quite often when a top lease is taken, the new lease will have a completely different number than the old lease. To find leases which have been charged off even though top leased, it may be necessary to compare the locations of the abandonments with the company's current holdings on a company land map. (The land department will have one.) If the new lease is obtained after the date of expiration of the old lease, the loss may be allowable. Of course, facts and circumstances are vital elements in each case.

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

Allocation of Geological and Geophysical Expenditures
  1. The geological and geophysical expenditures incurred in an area must be allocated to the leases acquired and retained therein. This can best be illustrated by the following example. The A Oil Company, as a result of preliminary survey work, obtains an option or selective type lease covering 10,000 acres at a cost of $4 per acre, or $40,000. The lease is for a term of 5 years and 6 months. The terms of the lease provide that a minimum of 25 percent of the acreage must be selected before the expiration of 6 months, a bonus of $10.00 per acre must be paid on the selected acreage, and a delay rental of $2.00 per acre per annum be paid on acreage selected. The preliminary survey, core drilling, and other geological and geophysical costs amounted to $24,000. Prior to the expiration of the first 6-month period, A Oil Company selected 2,500 acres under the lease for which they paid $25,000 bonus.

  2. The $40,000 option cost, the $24,000 geological and geophysical expenditures, if paid or incurred prior to the enactment of the Energy Tax Incentives Act of 2005 and the $25,000 bonus should be capitalized as leasehold costs of the 2500 acres of land selected. Watch for this type of transaction. The taxpayer may claim an abandonment of 7,500 acres and a loss of 75 percent of the $40,000 option cost plus all or part of the $24,000 geological and geophysical costs paid. This abandonment will appear as a credit to the leasehold account and a debit in the Expired and Surrendered Leases Expense. The leasehold account may explain this credit as "released acreage" when actually the company never had a lease on the acreage, but only an option. The lease record usually identifies a lease by its terms, bonus, acreage, and other provisions, thereby making it possible to identify each lease acquired.

  3. Remember that all of the geological and geophysical expenditures incurred in an area of interest are allocated to the acreage acquired and retained in the area. The acreage not retained is outside of the area considered to be favorable for development, regardless of the fact that an option was obtained as a protective measure during the study. See Rev. Rul. 77–188, 1977–1 CB 76.

Allocation to Leasehold and Equipment Costs
  1. An operator will sometimes purchase a block of leases from a broker in a lump sum purchase at the broker's purchase price plus a commission. Frequently, the broker's purchase price will be capitalized by the purchaser (operator) but the commission charged to expense. The entire cost to the operator should be capitalized and allocated to the lease acreage acquired in the purchase. You can identify this type of transaction by examining the commission expenses account and the purchase agreement. These two sources of identification are usually sufficient.

  2. Look into the subsequent year to ascertain whether some undue tax advantage may have resulted from the allocation of the purchase price. An allocation of a disproportionate share of the purchase price may have been made to acreage considered undesirable and that would be released early, thus the retained acreage would have low leasehold costs.

  3. When a producing property is purchased, the price paid must be allocated between leasehold and equipment. The cost basis is allocated between leasehold and equipment in proportion to their fair market value (FMV). Refer to Rev. Rul. 69–539, 1969–2 CB 141.

  4. Upon finding that a taxpayer has acquired a group of properties for a lump sum, the agent should obtain from the taxpayer:

    1. The allocation schedule and method

    2. The engineer's report on which the purchase was based

  5. The purchase of a group of producing properties, or a group of both producing and nonproducing properties, presents a complicated valuation problem. The best approach is to first allocate the total purchase price among the various properties. Although leasehold and equipment could be treated separately, at this point it is best to make allocations to each property. This helps keep values in perspective. Leasehold and equipment together (where applicable) are treated as a property unit. The reason for this is that most engineering appraisals, upon which purchases are based, value leasehold and equipment together. The valuation engineer projects future income and expenses of each property separately on an annual basis. Each future year's income is then discounted at the "going rate" to determine the present worth of all expected future net income to the property. The present worth of future income is then discounted a flat percentage to allow the purchaser a reasonable profit over and above interest on his/her investment. The projections include expected future capital investments as an expense and income from salvage of equipment as income. This type analysis necessarily includes income from sale of production and use of equipment in the same projection.

  6. The projections made in this manner give a realistic value to the "package" of leasehold and equipment. Quite often the value of equipment depends on the value of the oil and gas which it will produce. Seldom will equipment salvage value be anywhere close to its replacement cost, but its utility value (if substantial amounts of oil and gas can be expected to be produced by it) can easily equal its replacement cost. If no oil or gas will be produced by the equipment, its only value is its salvage value. This is usually much less than replacement cost.

  7. After the allocations have been made to each property, the property allocations will be divided between leasehold and equipment based on relative fair market values. In this allocation, normally equipment should not be valued at more than its replacement cost less depreciation or less than its net salvage value. Usually the value of the leasehold will have a bearing on the equipment value.

  8. The most appropriate time for the IRS to make corrections to a taxpayer's allocations of a lump sum purchase price is in the year of purchase. The agent should be alert for acquisitions of groups of assets which may require allocations of purchase price. Quite often any type of incorrect allocation can ultimately allow the taxpayer to claim an incorrect tax advantage. This is true regardless of whether the amount allocated to a particular property or asset is too high or too low. The situations to watch for are whether allocations were made which would result in the cost being written off too rapidly through too great an allocation to nonproducing properties which were abandoned, and too great an amount of cost recovered through depreciation by reason of an excessive allocation of cost to depreciable property. A distortion could result in excessive abandonment losses, excessive depreciation, or percentage depletion where cost depletion should apply.

  9. Allocation of purchase price may be a potential Whipsaw (aka Correlative Adjustments) issue. Refer to http://irm.web.irs.gov/link.asp?link=4.10.7.4.9 . When a material amount is involved, every reasonable effort should be made to secure the return of both sides to the transaction to secure consistency of treatment. The buyer and seller will seldom value the property in a like manner.

  10. The agent should be aware that Treas. Reg. 1.1245–1(a)(5) provides that, on the sale of IRC 1245 property and non-IRC 1245 property, if buyer and seller are adverse as to the allocation, any arm's-length agreement between buyer and seller will establish the allocation.

  11. In all cases in which an agent has a substantial problem with respect to allocation among properties and between leasehold and equipment, the agent should request engineering assistance.

  12. Refer to IRM 4.41.1.4.1.3 for further discussion with emphasis on the seller.

Complex Acquisition Arrangements

  1. Nonproducing oil and gas leases, as well as producing properties, are acquired by oil operators through arrangements that are unique to the petroleum industry. These acquisition arrangements differ vastly from the normal purchase of properties. For purposes of this handbook, these unusual acquisition arrangements are referred to as complex acquisitions. Included in this category are acquisitions of property by drilling for an interest, performance of services for an interest, the use of production payments, "farm-ins," and the acquisition of government leases.

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

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

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

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

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

  6. An additional problem that will be encountered is that the status of GCM 22730 is unclear at this time. It has not been revoked although it seems to have been partially superseded by the 1954 Code, case law, and the 1969 Tax Reform Act. Technical advice is recommended when this issue is considered and the adjustment is substantial.

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

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

    1. The contributor of services must receive a share of production, and the share of production is marked by an assignment of an economic interest in return for the contribution of services.

    2. The services contributed may not in effect be a substitution of capital.

    3. The contribution must perform a function necessary to bring the property into production or augment the pool of capital already invested in the oil and gas in place.

    4. The contribution must be specific to the property in which the economic interest is earned.

    5. The contribution must be definite and determinable.

    6. The contributor must look only to the economic interest for the possibility of profit.

Drilling Free Well for Interest in a Lease
  1. Drilling contractors will sometimes drill a well on an oil and gas lease in return for an interest in the lease. For instance, if a promoter has acquired a lease on 3,000 acres and lacks the necessary funds to drill a test well, an offer of a 6/8 interest in the lease in return for drilling a well may ensue. The drilling contractor will incur 100 percent of the drilling cost in return for a 75 percent interest in the 3,000 acre lease. Since the driller is entitled to only 75 percent of the working interest oil, 25 percent of drilling costs and equipment costs as leasehold cost must be capitalized. See Treas. Reg. 1.612–4(a). The promoter cannot deduct any cost of drilling or deduct any depreciation because no expenses were incurred.

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

  2. Rev. Rul. 77–176, 1977–1 CB 77, provides examples of the tax treatment to be afforded to the carrying party (operator) and the carried party (lease owner). Generally, the ruling states that the driller will be entitled to deduct 100 percent of the intangible drilling and development costs (IDC) if the arrangement is a true carried interest. Refer to IRM 4.41.1.2.4.8.4 references. The driller will, however, receive income to the extent of the value of the property outside of the drill site. Examiners should carefully inspect the legal instruments and lease assignments where "carried interests" are present to determine if acreage outside of the drilling site is conveyed as consideration of drilling. See Rev. Rul. 77–176, 1977–1 CB 77 for instructions.

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

Drilling Site Location as Consideration for a Net Profits Interest
  1. A net profits interest is considered to be an overriding royalty payable out of the working interest income. SeeIRC 614 and Rev. Rul. 73–541, 1973–2 CB 206. A conveyance of a drilling site in return for a net profits interest is similar to a situation in which an operator conveys a working interest in a lease and retains an overriding royalty interest. The results would essentially be the same on nonproducing properties. The operator who drills the well would be entitled to deduct 100 percent of the IDC, and the transferrer would be considered to have merely retained an overriding royalty interest.

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

Acquisition of Property by a Production Payment
  1. A production payment is a share of the minerals produced from a lease, free of the cost of production, that inter alia terminates when a specified sum of money has been realized. Production payments may be reserved by a lessor or carved out by the owner of the working interest. Refer to Treas. Reg. 1.636-3(a)(1) and (2) and IRM 4.41.1.3.1.4 for further definition.

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

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

Acquisition of Government Oil and Gas Leases
  1. The United States Department of the Interior announces blocks of acreage available for lease by competitive bid under the Outer Continental Shelf Lands Act of a specific date.

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

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

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

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

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

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

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

    1. The BLM announces the tracts by size, legal description, and date they are to be available for leasing.

    2. Interested persons are allowed to file an application to lease any or all tracts, but each separately described lease requires a separately filed lease application.

    3. A nominal nonrefundable filing fee of $10 is required for each filing application.

    4. A person may file only one application for any one tract.

    5. On the prescribed date, a lottery-type drawing is held by the BLM.

    6. The "winner" is then awarded the lease and must then pay the first year's rental to the BLM. All $10 filing fees are retained by the BLM.

  9. The drawings have all the characteristics of a lottery.

    1. A fee is charged for entry in the "drawing."

    2. The winner is awarded a property far in excess of the entry fee plus delay rentals.

    3. The fee is nonrefundable.

    4. The actual drawing is held, utilizing card tickets very similar to lottery tickets.

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

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

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

    1. The taxpayer filed an application for a Government lease and paid the first-year rental.

    2. In the same year, the taxpayer assigned rights under the application to a third party for cash and a further agreement that, if the lease was issued, the third party would pay an additional sum and allow the taxpayer to retain an overriding royalty.

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

Overhead Costs of Oil Company Departments
  1. Certain departmental overhead costs should be allocated to the cost of acquiring oil and gas leasehold properties. This includes both developed and undeveloped properties. For a discussion of the various items that should be considered for capitalization in property acquisitions, refer to IRM 4.41.1.3.2.2.

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

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

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

Intangible Drilling and Development Cost (IDC)

  1. In the case of oil and gas wells, a taxpayer has an option to treat intangible drilling and development costs as either capital expenditures, under IRC 263(a), or as expenses as provided in IRC 263(c) and Treas. Reg. 1.612–4. In the event that the taxpayer has elected to capitalize such costs, they become part of the depletable investment recoverable through the depletion deduction Treas. Reg. 1.612–4(b)(1). Refer to United States v. Dakota-Montana Oil Co., 288 U.S. 459 (1933); 12 AFTR 18; 3 USTC 1067. If a taxpayer has elected to capitalize IDC, Treas. Reg. 1.612–4(b)(4) provides an election to charge to expense the IDC with respect to nonproductive wells.

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

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

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

  2. Taxpayers that initially elected to expense IDC have the opportunity to make a secondary election to capitalize and amortize, under IRC 59(e), all or part of the IDC. For each tax year such taxpayers may elect to capitalize any portion of the IDC and amortize the cost on a straight line basis over 60 months. The amount subject to the IRC 59(e) election will not be treated as a tax preference item in determining the taxpayer's Alternative Minimum Tax (AMT). The amount that a taxpayer elects to amortize for a particular taxable year is generally irrevocable. Examiners should review Treas. Reg. 1.59-1 for the rules regarding the election.

  3. Refer to Exhibit 4.41.1-5 for a classification of expenditures in acquisition, development, and operation of oil and gas leases.

Integrated Oil Companies
  1. In the case of a corporation which is an integrated oil company, IRC 291(b) provides that the amount allowable as a deduction under IRC 263(c) is reduced by 30 percent. This provision applies to IDC paid or incurred after 1986. The amount not allowable (30 percent) as a current expense is allowable as a deduction pro-rated over a 60-month period beginning with the month in which the costs are paid or incurred, and is not to be taken into account for purposes of determining depletion under IRC IRC 611. Refer to IRC 291(b)(2)(5)..

  2. For purposes of IRC 291(b) an "integrated oil company," with respect to any taxable year, means any holder of an economic interest with respect to crude oil who is not an independent producer. An independent producer is a person who is allowed to compute percentage depletion under the provisions of IRC 613A(c).

IDC Incurred Outside of the United States (Foreign IDC)
  1. There are special rules for IDC incurred outside the United States. IRC 263(i) requires IDC paid or incurred outside the United States to be capitalized. It must be capitalized to the depletable basis of the property or amortized on a straight line basis over 10 years. The capitalized IDC which is attributable to installation of casing, derricks, and other physical property must be recovered through depreciation. See Rev. Rul. 87–134, 1987–2 CB 69.

  2. There is a special exception for lDC incurred or paid for certain North Sea operations. It provides that the foreign IDC capitalization rules do not apply to the IDC which was incurred by a United States company pursuant to a minority interest in a license for Netherlands or United Kingdom North Sea development. The interest must have been acquired prior to 1986. The U.S. company is still required to capitalize 20 percent of such IDC incurred. The requirement to capitalize foreign IDC does not apply to dry holes or nonproductive wells. The "North Sea IDC Transition Rule" issue was decoordinated in 2009. Refer to http://lmsb.irs.gov/hq/c/memos/Miller/2009-071309.asp.

  3. An issue has arisen where IDC is subject to an election to be deducted currently under IRC 263(c), and where a portion of IDC amortized under IRC 291(b) was paid or incurred with regard to a nonproductive well.

    1. Can a taxpayer file an amended return and deduct the unamortized IDC in the year paid or incurred for wells that prove to be nonproductive after the close of the taxable year?

    2. The Service's view is that an amended return may be filed for that year deducting the unamortized IDC for the wells that prove to be unproductive after the close of the taxable year. If the taxpayer previously deducted the unamortized IDC in the year the nonproductive well was plugged and abandoned, an amended return must be filed taking into income the amount that was deducted.

  4. Refer to Rev. Rul. 93-26, 1993 CB 50 for how to account for the unamortized amounts when the underlying property is sold or the taxpayer ceases to be an integrated producer.

Distinction between IDC and Nonproductive Well Costs
  1. Examiners should be aware that there are some important differences in the tax treatment of Intangible Drilling Costs (IDC) and "nonproductive well costs" . While the treatment of IDC under the IRC is generally favorable for taxpayers, the treatment of nonproductive well costs is even more favorable. Nonproductive well costs are the IDC incurred in the drilling of a nonproductive well. The code, regulations, and revenue rulings do not use the term “dry hole” but it is somewhat analogous. Treas. Reg. 1.1254-1(b)(1)(vi) defines a nonproductive well as:

    "[a] well that does not produce oil or gas in commercial quantities, including a well that is drilled for the purpose of ascertaining the existence, location, or extent of an oil or gas reservoir (e.g., a delineation well). The term nonproductive well does not include an injection well (other than an injection well drilled as part of a project that does not result in production in commercial quantities)" .

  2. The production of oil and gas in "commercial quantities" is not defined by the code, regulations or revenue rulings. A brief mention in the Committee Report on P.L. 94-455 (Tax Reform Act of 1976) indicates that commercial quantities are relative to the cost of drilling the well. As explained in Rev. Rul. 84-128, 1984-2 CB 15, a well that is merely temporarily shut in does not constitute a nonproductive well for purposes of computing the AMT tax preference for IDC under IRC 57(a)(2). Similarly, a well should not be treated as nonproductive if it is still producing oil and gas, or is capable of being restored to economic production, even if it has not yet generated enough income to offset drilling and equipment costs.

  3. For purposes of this section of the IRM the term "successful well" will be used to describe a well that is not a nonproductive well. Differences in tax treatment of IDC on successful wells and nonproductive wells costs include:

    • Taxpayers normally elect to currently deduct IDC incurred in the U.S. For those that elect to capitalize such IDC, Treas. Reg. 1.612-4(b)(4) provides a secondary election whereby IDC associated with nonproductive wells can still be currently deducted.

    • IRC 263(i) requires that IDC incurred by U.S. taxpayers in drilling a successful well outside the United States must be capitalized and recovered via either cost depletion (IRC 611) or via amortization over 10 years. In contrast, nonproductive well costs incurred by U.S. taxpayers for foreign wells are currently deductible.

    • IRC 291(b) requires integrated oil companies to capitalize 30 percent of the IDC incurred in drilling successful wells in the U.S. over 60 months. In contrast, 100 percent of nonproductive well costs incurred by integrated oil companies are currently deductible. See the legislative history of IRC 291 discussed in Technical Advice Memorandum 9418002.

    • IDC that is currently deductible under IRC 263(c) or amortized during the tax year under IRC 291 forms the basis of computing an AMT tax preference item under IRC 57(a)(2). However, the costs of drilling a nonproductive well are not included in the AMT preference item. Refer to IRC 57(b)(2)(B)(i) .

    • IRC 1254 provides that IDC is subject to recapture upon the sale of the underlying mineral property. However, Treas. Reg 1.1254-1(b)(1)(vi) generally provides that recapture does not apply to costs associated with drilling a nonproductive well

  4. Without conclusive evidence that a well is nonproductive as of the date of filing its original tax return, a taxpayer should assume that IDC incurred during the year was related to a successful well. If the well is later determined to be nonproductive the taxpayer may file an amended return to treat the IDC as nonproductive for that taxable year rather than the year in which the well was determined to be nonproductive. See the discussion of legislative history from the Tax Reform Act of 1976 that is cited in IRS Technical Advice Memorandum 9418002.

  5. Both IDC on successful wells and nonproductive well costs are normally reported as an Other Deduction on Line 26 of a corporate income tax return. Examiners may find that they are combined and reported only as "Drilling Costs" . Examiners should request separate lists of the two types of costs by well (preferably in electronic format) so they can be analyzed. Examiners should also look for unusually large figures and also for figures that suggest an estimated amount was deducted (e.g., exactly $1,250,000).

Plug and Abandonment Versus Temporary Abandonment
  1. The tax treatment of drilling costs is dependent to a large degree upon operational decisions made at the conclusion of the drilling phase. When the drilling of a well reaches total depth the operator must decide how to proceed. Information will first be gathered from well "logging" tools (sensors) to help determine certain characteristics of the geologic layers and any fluids contained within. Other tools that can obtain small cores and fluid samples from prospective reservoirs may also be lowered into the well and then retrieved. On rare occasions the operator will attempt to produce the well to verify that a commercial rate of oil and gas can be achieved. Based on the results, the operator will place the well into one of the following conditions:

    1. Plugged and Abandoned ("P&A" ). Cement will be placed within the well in a number of intervals and a metal plate welded to the top near the ground level. For offshore wells the final step in the "P&A" process is to sever the well a few feet below the mud line. The operator will file a "P&A" or "Dry Hole" report with the appropriate regulatory agency.

    2. Temporarily Abandoned. The operator will leave the well in a state where it can placed into production by future operations, utilized for the drilling of a deeper section or sidetracks, or even "P&A'd" . The drilling rig may install the final string of casing in the well before leaving the drill site. Future operations, such as installing the tubing and perforating the well, may be performed by a less expensive "completion rig" . The operator will file a Temporarily Abandoned or Idle Well report with the appropriate regulatory agency.

    3. Shut-in. The final string of casing and the well tubing is installed. The well is perforated and the christmas tree is installed. A retrievable plug or check-valve may be set in the tubing just below the christmas tree for safety purposes, but the well is otherwise ready to produce. Shut-in status may occur when there is not yet a pipeline or tank battery for the well to flow into. The operator will file a Shut-in or Idle Well report with the appropriate regulatory agency.

    4. Producing. The well is completed and production to the pipeline or tank battery has been established. The operator will file a Completed Well report with the appropriate regulatory agency.

  2. Since there are numerous regulatory agencies, the title of the well status reports and the information that must accompany them when submitted varies. However, when submitting a report for any status other than "P&A" , geologic formations that appear to be hydrocarbon bearing must usually be identified. This information can be useful in disputing that a well is “nonproductive” or that the underlying mineral property is worthless and should be written off as an abandonment loss.

  3. Tax Considerations - When a well has been drilled and then placed into either temporarily abandoned or shut-in status, the drilling costs should generally be treated as IDC. Examiners often find that wells that are temporarily abandoned are improperly treated as nonproductive wells or improperly written off as abandonment losses. When a well is plugged and abandoned immediately after drilling, the well is clearly nonproductive, and drilling costs can be treated as such. When the "P&A" operation occurs some time after the completion of drilling operations, a review of the facts will be required to determine if previously incurred IDC was associated with the drilling of a successful well. The assistance of an IRS engineer may be necessary. The cost of the "P&A" operation itself could be deducted as either nonproductive well costs or operating expenses of the property where the well is located. Refer to IRM 4.41.1.3.2.4.1.

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

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

Prepaid Expenses
  1. For taxpayers using the cash basis method of accounting, IDC is deductible in the year paid, under certain conditions, although the work is performed in the following year. Refer to Pauley v. United States , 63–1 USTC 9280; 11 AFTR 2d 955.

    Example:

    Taxpayer A owns 100 percent of the working interest in an oil and gas lease and enters into a drilling agreement with Taxpayer B for the drilling of a well on Taxpayer A's property. The drilling agreement provides that Taxpayer B will drill the well to the desired depth for $500,000 and will begin the work as soon as Taxpayer B has a rig available, but no later than January the next year. The agreement, executed in December, requires Taxpayer A to pay the $500,000 fixed price upon execution of the contract in order for Taxpayer B to have sufficient funds to drill the well. Taxpayer A is on the cash basis of accounting and paid Taxpayer B as provided in the agreement on December 29, 1999.

  2. The Government's position regarding the deduction of prepaid IDC by a cash basis taxpayer is set out in Rev. Rul. 71–252, 1971–1, CB 146 and Rev. Rul. 71–579, 1971–2, CB 225. The Tax Court sustained parts of the IRS position in Keller v. Commissioner , 79 TC 7 (1982). Ordinarily, the prepaid expense is deductible if:

    1. The prepayment is made for a bona fide business purpose.

    2. The prepayment does not substantially distort income.

    3. The drilling contract requires a prepayment of the agreed amount. The prepayment must not be a mere deposit.

    4. The prepayment covers the full 100 percent working interest.

    5. The actual drilling of the well was begun in the first part of the next year.

    6. Some well site work was done prior to the year end.

  3. In the above example, Taxpayer A is entitled to deduct the prepaid amount in 1999 since Taxpayer A has met all the conditions set forth in the revenue rulings.

  4. The examining agent should be aware that, generally, when there are several working interest owners of the property, the operator of the property is the person that makes the contacts with the drilling company and enters into the drilling contract for the drilling of the well. The drilling contractor will require the prepayment of the agreed amounts from the operator. It is, therefore, unlikely that a drilling contract would require a prepayment from any interest owners other than the operator. The prepayment to the operator by a nonoperator working interest owner does not satisfy the requirements for a deductible prepayment unless the operator was required to make a prepayment in accordance with the rules set out above. The method of accounting used by the operator generally controls the deductibility of any amount to the working interest owners. See IRM 4.41.1.2.4.7.4. The drilling contract and prepayment agreement should always be examined to learn the facts regarding every material prepayment requirement.

  5. The above discussion and revenue rulings apply only to the cash basis taxpayer. The deduction to the accrual basis taxpayer is controlled by the general rules regarding the accrual of any type of expense including the economic performance requirements of IRC IRC 461(h).

Method of Accounting
  1. The method of accounting used by the individual taxpayer, as well as by the operators of working interests, is very important in determining the year of deduction of intangible drilling and development expenses. Because the cash basis method of accounting gives the taxpayer more control over the timing of a deduction, most taxpayers use this method of accounting.

  2. Cash Method — The cash method of accounting in the oil and gas business is no different than in any other business. The expenses are deductible when incurred and paid, and the income is taxable when received. The general rules of IRM 4.41.1.2.4.7.4 should be kept in mind when there is an operator and other working interest owners that have joint billings involved.

  3. Accrual Method — The accrual method of accounting in the oil and gas business is similar to any other business. The expenses are deductible when all events have occurred to fix the liability and income is taxable when received or earned. If the taxpayer owns drilling equipment and drills its own wells, the IDC is deductible when incurred. If the taxpayer has contracted for the drilling of the wells, the provisions of the drilling contract will fix the liability for the accrual of the expense deduction. Special attention should be given to the contract provisions in order to determine the proper accruals of any year end.

  4. Completed Contract Method — The use of the completed contract method of accounting for the deduction of IDC can not be used by the accrual basis taxpayer to postpone the deduction until a succeeding year. The cost must be deducted in the year paid or incurred, depending on the taxpayer's general method of accounting.

Contract Provisions
  1. Turnkey — The Turnkey drilling contract is an agreement that calls for the drilling contractor to drill a well to a specified depth and furnish certain equipment and supplies for a preagreed lump-sum price. Since this type of contract does not separate the tangible equipment cost from the intangible drilling cost, the agent should make sure that the leasehold and equipment costs are properly capitalized. A common problem is for the taxpayer to deduct the entire percentage of the Turnkey price without regard to the capital items included in the contract. To the accrual basis taxpayer, the accrual of the expense should only be made when all the events to fix the liability have been satisfied including the economic performance requirements of IRC IRC 461(h). There are several variations of the general Turnkey contract which might call for different stages of completion and equipping of the well. The contract provisions should be examined in order to determine the proper tax treatment of the lump sum expenditure.

  2. Footage — The Footage contract provides for the drilling contractor to perform specific services to drill the hole at a specified price per foot. This type of contract usually provides that the contractor will also be paid an hourly or daily work rate for any other service performed during the drilling of the well. If the well is a productive well, additional cost will be incurred for the completion and equipment on the well. These costs will be in addition to the footage drilling price. The agent should make sure that all tangible equipment costs are capitalized and all IDC identified properly.

  3. Day Work — The Day Work drilling contract generally provides for the drilling contractor to drill a well and be paid for services based on an agreed rate per day. This type of contract is usually used by a drilling contractor where problems with the geological formations may be encountered and in unfamiliar areas. This type of drilling contract avoids the risks to the driller inherent in Turnkey and Footage contracts. The loss of drilling mud, high gas pressure blowouts, "fishing jobs," or unusually hard formations are examples of problems that can cause delays and increase the cost to the contractor. The lease operators will be charged for "third-party" costs, such as, drilling mud, drilling bits, fuel costs, water and site preparation cost, in addition to the day work rate charged by the drilling contractor. The agent should look at these drilling contracts and agreements to make sure the proper costs and charges are deducted as IDC.

Agency Relationships
  1. It is common practice in the oil and gas industry for joint owners of working interests to designate one owner as the "operator" of their properties. For this purpose "operator" is considered to be the person who bears the most responsibility for the management and day to day activities of drilling, completing and operating the wells. Normally, the operator performs duties in accordance with an operating agreement that all joint owners have endorsed. The operator manages the drilling, completing, and operating efforts on the property, pays all expenses, and bills joint owners for their share of the expenses. The operator is usually from one to six months behind in billing to the several joint owners. An agency relationship exists between the operator and the nonoperator, and the timing of the deduction to the nonoperator is an important item.

  2. The tax accounting for the cash basis nonoperator will be controlled by the operator's payment of the expense items. The IDC and operating expenses should be deducted in the year paid or incurred even though they may be reimbursed in a later year. The operator must have incurred and paid the expense before the nonoperator's deduction is allowable. The nonoperator has not paid until payment is made by the operator. See McAdams v. Commissioner, 52–2 USTC 9373, 198 F. 2d 54 (5th Cir. 1952).

  3. The deductions of the accrual-basis nonoperator will be allowable only if the accrual-basis operator has an expense that is properly accrued, or if the cash basis operator has actually paid the expense.

  4. The agent should be aware of this problem area, and the legal relationship between the parties should be determined for a proper timing of the expense deductions. The examination of the operator's and nonoperator's returns should include the examination of the year-end expenses and, where material errors are found, corrected.

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

Operator Drilling Own Well
  1. Many times the owner-operator of an oil and gas lease owns drilling equipment as well as the oil and gas wells being drilled. If the taxpayer has made the election to expense the intangible drilling and development cost, this cost incurred or paid may be deducted. The timing of the deduction depends on the method of accounting. These expenses include all direct costs, indirect costs, and the current depreciation of the equipment. Refer to Commissioner v. Idaho Power Co., 418 US1 (1974).

  2. The scope of the examination of an owner-operator drilling its own wells should be extended to the operating expense accounts to ensure that all costs attributable to the drilling of the wells are properly classified as intangible drilling costs. The proper classification is necessary because of the computations of tax preference items, depletion, and any gain or loss on the subsequent disposition of the property. If the taxpayer owns something less than 100 percent of the working interest and pays all the cost of drilling the well, only the intangible costs attributable to the working interest percentage owned is deductible and the balance is capitalized to the leasehold basis.

  3. If the taxpayer owns only a fractional interest in the working interest and drills the well on the property for all the working interest owners, the taxpayer should realize a profit or loss on the drilling of the well separate from the IDC deduction.

    Example:

    Taxpayer A, B, and C each own 1/3 of the working interest of an oil and gas lease. Taxpayer A also owns the necessary drilling equipment to drill the well. Taxpayer A agrees to drill the well to 8,000 feet for $360,000. Each owner agrees to pay 1/3 of the price. Taxpayer A drilled the well as agreed at a total cost of $300,000. Taxpayer A has an IDC deduction of $100,000 and an ordinary profit from the drilling of the well of $40,000. Taxpayers B and C each have an IDC deduction of $120,000.

  4. In this example, notice the factual differences from the preceding example in that Taxpayers B and C are paying for IDC and an interest in a lease. Assume that Taxpayer A owns 100 percent of the working interest in an oil and gas lease. Taxpayer A approaches Taxpayers B and C with a deal and transfers to each of them a 1/3 interest in the property with the agreement to drill an 8,000-foot well on the property for a "turnkey" price of $150,000 each. Taxpayer A had acquired the property several years before for $9,000. The well was drilled by Taxpayer A at a total cost of $300,000. (A price of $45 per foot is the "going" price for drilling in this area to this depth.) Taxpayer A has made a sale of 2/3 leasehold interest and entered into a drilling contract with Taxpayers B and C. Taxpayer A realizes a gain on the sale of the leasehold of $54,000, a profit on the drilling agreement of $40,000, and has an lDC deduction of $100,000. Taxpayers B and C have a leasehold cost of $30,000 each and an IDC deduction of $120,000 each. See Rev. Rul. Rev. Rul. 73–211, 1973–1 CB 303.

  5. Assume the same facts as in the above example except that the payment for the transfer of the 2/3 leasehold interest to Taxpayer B and Taxpayer C was conditioned on the drilling of a producing well. Refer to Rev. Rul. 75–304, 1975–2 CB 94. Since the IDC deductions are available to the working interest owners only, Taxpayer A is entitled to deduct the entire $300,000 cost of drilling the well. Taxpayer A, therefore, has a gain on the sale of the leasehold of $294,000, of which $200,000 is ordinary income in accordance with IRC 1254 and the balance of $94,000 is controlled by IRC 1231. This is assuming that Taxpayer A is not in the trade or business of selling oil and gas leases, and the oil and gas lease was not held for sale to customers. Taxpayers B and C have no deductions for intangible drilling and development costs, but each must capitalize the $150,000 to their leasehold basis.

  6. The examination of taxpayers that have drilling and development arrangements, such as those mentioned above, should include the examination of the assignment of the property, letter agreements, operating agreements, and drilling contracts. Before making an examination of an oil and gas operator's IDC, the examiner should be familiar with what qualifies as IDC and carried interest arrangements. The Audit Technique Guide to the Oil and Gas Industry http://www.irs.gov/Businesses/Small-Businesses-&-Self-Employed/Audit-Techniques-Guides-(ATGs) is a good starting point, and it identifies 11 revenue rulings that address IDC in the context of sharing arrangements. Rev. Rul. 75-446, 1975-2 CB 95 and Rev. Rul. 80-109, 1980-1 CB 129 are additional rulings that deal specifically with carried interest arrangements. The textbook used for Oil and Gas Unit II training should also be consulted. http://lmsb.irs.gov/hq/mf/2/training/cpa/lmsb_regular_training/11036_oil_gas_phase_II_2005.asp

Partnerships
  1. Very often the partnership form of doing business is used in the oil and gas industry since it is a convenient means of bringing a large number of widely scattered investors or owners into one joint business undertaking. During the development period of oil and gas properties, the IDC may be allocated to the partners in accordance with the partnership agreement. IRC 704(b) and Treas. Reg. 1.704–1(b) provide that this allocation of income, expenses, gains, losses, or credits can be made in accordance with this agreement if such allocation has "substantial economic effect." For a complete explanation of "substantial economic effect" see Treas. Reg. 1.704–1(b) (in its entirety), and court cases Orrisch v. Commissioner, 55 TC 395 (1970), and Allison v. U.S., 83–1 USTC 9241 (Fed. Cir. March 7,1983).

  2. The election to expense the IDC must be made by the partnership the first year the partnership incurs IDC. If the partnership agreement so provides, subject to the provisions of Treas. Reg. 1.704–1(b), it is permissible to allocate the partnership expenses, such as IDC, to the partner or partners contributing the funds for the expenditures.

  3. In the examination of oil and gas partnerships, it is important to first verify that a true partnership exists. Once verified, it is very important to always inspect the partnership agreement for provisions regarding allocations of income, expenses, gains, losses, and credits. If there is a change in partners or the ratio of allocations of income, expenses, gains, losses, or credits during the partnership year, refer to Rev. Rul. 77–310 and Rev. Rul. 77–311, 1977–2 CB 217 and 218 to prevent the retroactive allocations of these items. Special care should be taken to make sure that all items are allocated in accordance with the sharing ratio in effect at the time the income, expenses, gains, losses, or credits were earned or incurred.

Free Well Drilled for Fractional Interest
  1. Many times an interest in an oil and gas lease will be transferred to another person in order to get a well drilled on the property at no cost to the transferrer.

    Example:

    Taxpayer A owns 100 percent of the working interest in an oil and gas lease and agrees to assign to Taxpayer B 50 percent of the working interest in the property if Taxpayer B will drill and equip a well on the property at Taxpayer B's expense.

  2. This arrangement is known as a "free well" arrangement and the transfer of the property is sometimes called a "farm-out" to Taxpayer B from Taxpayer A . Taxpayer A does not create a taxable event on the transfer of the property to Taxpayer B. Since Taxpayer B owns only 50 percent of the working interest in the property, Taxpayer B can only deduct 50 percent of the IDC of drilling the well. The balance of the cost must be capitalized to the leasehold basis. Likewise Taxpayer B can depreciate only 50 percent of the tangible equipment cost, with the balance of the cost to be capitalized to Taxpayer B's leasehold basis. If the well is not a producer, Taxpayer B still must capitalize 50 percent of the lDC to the leasehold basis. Taxpayer B may deduct the leasehold cost as a loss in the year the property is abandoned, surrendered, released, or otherwise proven worthless. See Treas. Reg. 1.612–4j and Rev. Rul. 70–657, 1970–2 CB 70.

  3. In the examination of both Taxpayer A and B above, all instruments regarding the "free well" arrangement should be inspected. This should include the assignment of the property, letter arrangements regarding the drilling of the well, and operating agreement. These instruments should give all the details of the arrangement so that the examiner can determine the proper tax treatment. Special care should be given to the examination of Taxpayer B to make sure the proper IDC has been deducted, the proper leasehold cost has been capitalized, and the investment tax credit has only been claimed on the amount capitalized to the depreciable asset account.

Carried Interest
  1. The term "carried interest" generally refers to an arrangement where one co-owner of an operating interest (the "carrying party" ) incurs an obligation to pay all of the cost to develop and operate a mineral property, in exchange for a right to recoup this investment out of the proceeds of first production from the property. After the investment is repaid, any subsequent production is split between the co-owner(s). The co-owner(s) not obligated to pay for the development and operation hold a carried interest in the mineral property until the carrying party's initial investment is repaid.

  2. A typical carried interest arrangement is as follows:

    Example:

    Taxpayer A owns 100 percent of the working interest in an oil and gas lease and is interested in having a well drilled on it.
    Taxpayer A assigns to Taxpayer B the entire working interest in the property, and Taxpayer B agrees to drill, complete, and equip a well free of all cost to Taxpayer A.
    Taxpayer B is to retain 100 percent of the working interest until the entire cost is recovered (including drilling, completing, equipping, and operating the well) out of the production from the property. After Taxpayer B recovers cost, 50 percent of the working interest in the property is to be transferred back to Taxpayer A, and the working interest ownership is to be owned equally by each thereafter.
    • Normally, Taxpayer A and B will elect out of the provisions of Subchapter K following Treas. Reg. 3930 and 3948 or Treas. Reg. 1.761–2(a).
    • The arrangement above is the most common carried interest. Taxpayer A realizes no gain or loss on the transfer of the property. Drilling a productive well would only increase the value of the property interest to be returned to Taxpayer A. The basis in Taxpayer A's residual interest would take the basis of the entire property prior to the transfer. After Taxpayer B has recovered cost in accordance with the carried interest arrangement and transfers back to Taxpayer A 50 percent of the working interest, Taxpayer A realizes no taxable event because of the transfer. Taxpayer A has no basis in the depreciable equipment and, therefore, has no depreciation or investment tax credit on the value of the equipment acquired.
    • Since Taxpayer B owns all the working interest and operating rights to the property during the drilling of the well and is entitled to all the income from the entire working interest during the complete payout period of the well, Taxpayer B is entitled to deduct all the lDC of drilling the well. Taxpayer B is required to capitalize all equipment cost and should claim the investment tax credits on the qualified equipment purchases. Taxpayer B will report all income and expenses from the property during the entire payout period. After payout, Taxpayer B must capitalize to Taxpayer B's leasehold basis the unrecovered equipment cost attributable to the half interest which reverts to Taxpayer A. Taxpayer B must also recapture the investment tax credit attributable to the equipment transferred to Taxpayer A. See Rev. Rul. 71–207, 1971–1 CB 160.

  3. The examination of Taxpayers A and B above should include an inspection of the lease agreement, carried interest agreement, operating agreement, and accounting for the carried interest payout. The examiner should make sure that Taxpayer B has the full working interest in the lease during the complete payout period before allowing Taxpayer B to deduct the entire IDC. Rev Rul. 71-207 provides an example of a complete payout. Taxpayer B must also report all the income and expenses from the property. Normally, both Taxpayer A and B will "monitor" the profits from the property for payout purposes; this payout amount can be compared to the tax profit for comparison purposes. Any deviation from the usual carried interest arrangements should be inspected closely since failure to qualify may result in the disallowance of part of the IDC.

  4. Another type of carried interest arrangement that is different from the above and has a different tax treatment can be illustrated as follows:

    Example:

    Taxpayer A owns 100 percent of the working interest in an oil and gas lease and is interested in having a well drilled on the property.
    Taxpayer A assigns to Taxpayer B the full working interest in the property and Taxpayer B agrees to drill, complete, and equip a well on the property free of all cost to Taxpayer A.
    Taxpayer B is to retain the full working interest until Taxpayer B has recovered $400,000 out of the net profits from the property. At recovery, 50 percent of the working interest in the property reverts back to Taxpayer A.
    Taxpayer B knows that it will cost $500,000 to drill and complete the well and another $100,000 to equip the well. In order for Taxpayer B to be entitled to deduct all the IDC, Taxpayer B must own the entire working interest or operating rights in the well during both the drilling period and the payout period.
    • Since Taxpayer B will not own the entire operating rights during the entire payout period, Taxpayer B is not entitled to deduct all the IDC.
    Taxpayer B must capitalize to the leasehold basis the IDC and depreciable equipment cost applicable to Taxpayer A. Taxpayer B must capitalize $250,000 ($500,000 x 50 percent) of the IDC and $50,000 ($100,000 x 50 percent) of the equipment cost to leasehold basis.
    Taxpayer B must also report all the income and expenses from the property during the $400,000 payout period.
    Taxpayer A has no taxable event because of the transfer. See Rev. Rul. 70–336, 1970–1 CB 145, Rev. Rul. 71–206, 1971–1 CB 105 and Rev. Rul. 80–109, 1980–1 CB 129.

  5. In order to know all the facts of the carried interest arrangements, the lease assignments, carried interest agreements, operating agreements, and any letter agreements must be studied.

  6. There are several types of carried interest arrangements that are used in the oil and gas business. They have different provisions to suit the taxpayer's individual needs and desires. The agent should study the instruments and then do the research needed to apply the law based on the facts of each case. Refer to IRM 4.41.1.4.4 for further discussion.

"Cash and Carry" Arrangements
  1. The emergence of "shale plays" in the U.S. has led to arrangements between parties that vary from the traditional farm-in and free-well arrangements. Generally known as "cash and carry" arrangements, an illustration of the implementation of a basic one is provided below.

  2. An explanation of the tax treatment of an operating interest in oil and gas property received for a drilling well is provided in Rev. Rul. 77-176, 1977-1 CB 77:

    "[G]CM 22730, 1941-1 C.B. 214 provides, in part, that when drillers or equipment suppliers and investors contribute materials and services in connection with the development of a mineral property in exchange for an economic interest in such property, the receipt of the economic interest does not result in realization of income. The contributors are viewed as not performing services for compensation, but as acquiring capital interests through an undertaking to make a contribution to the pool of capital. To come within the holding of GCM 22730, the economic interest acquired must be in the same property to the development of which the materials and services are contributed. With respect to the transferor of the economic interest, GCM 22730 states that such transferor has parted with no capital interest but has merely given the transferee (driller, equipment supplier, or investor) a right to share in production in consideration of an investment made."

    Example:

    OilCoA owns 100 percent working interest (WI) in Lease1 which has good potential for development by a single well. OilCoA's depletable basis is $1000x. For economic and operational control purposes, OilCoA desires an outside party to drill and equip a well on Lease1 at its own cost to earn a 40 percent WI in Lease1. The estimated cost to drill and equip a well is $3000x.

    OilCoA decides to accept an offer made by OilCoB whereby it earns a 40 percent WI in Lease1 by paying $300x free and clear to OilCoA in addition to paying the cost to drill a well and equip that well, if successful. The agreement requires the $300x to be paid to OilCoA upon execution of the agreement. The payment is not refundable in the event the well is nonproductive (i.e., a dry hole is drilled). The agreement also provides that OilCoB must commence drilling by a certain date or else it loses its right to drill and earn the 40 percent WI. There is no payout provision, the effect of which is that immediately after the well is drilled and equipped (or P&A'd if dry) each company's fractional WI in Lease1 takes effect. The parties agree to elect out of the partnership provisions of Subchapter K of the Code. OilCoB fulfills its obligation by drilling a well. It incurs $2500x of IDC and $500x of lease and well equipment cost. OilCoA assigns a 40 percent WI to OilCoB.

    Consequently, OilCoB in the above example made a contribution to the pool of capital (the reservoir beneath Lease1) by paying the cost to drill and equip the well. The receipt of a 40 percent WI is not compensation for services, and does not constitute a taxable event. In accordance with Treas. Reg. 1.612-4(a), OilCoB can deduct only 40 percent of the IDC it incurred ($1000x = $2500x × 40 percent). Sixty percent of OilCoB's expenditure for IDC becomes part of its depletable basis ($1500x = $2500x × 60 percent). The regulation similarly affects OilCoB's expenditure of $500 for equipment. Only 40 percent can be recovered via depreciation ($200x = $500x × 40 percent) and 60 percent is added to OilCoB's depletable basis ($300x = $500x × 60 percent). Finally, since OilCoB's payment of $300x free and clear to OilCoA was not used for items necessary for drilling or for acquisition of equipment, the $300x is added to OilCoB's depletable basis.

    For OilCoA, its transfer of a 40 percent WI also does not result in a taxable transaction. OilCoA has parted with no capital interest, rather its 60 percent retained WI is with respect to a larger pool of capital (Lease1 and OilCoB's capital). Consequently, OilCoA transfers its $1000x basis in Lease1 to its retained 60 percent WI.

    Upon execution of the agreement, the $300x received by OilCoA is in the nature of an option payment by OilCoB to have the right to acquire a working interest in Lease1. OilCoA should report the $300x as proceeds from a capital transaction if and when OilCoB earns its 40 percent WI pursuant to the agreement. Since OilCoA must transfer its entire basis in Lease1 to its retained 60 percent WI, it has no basis to offset the $300x. Had the agreement terminated without OilCoB earning any interest in Lease1 (e.g., by failure to drill the well), OilCoA would report the $300x as ordinary income (not subject to depletion) as payment on a lapsed option. Refer to Rev. Rul. 57-40, 1957-1 CB 266, citing Virginia Iron Coal & Coke Co v. Commissioner, CA-4, 38-2 USTC 9572, 99 F2d 919. Cert. denied, 307 US 630.

Free Well Drilled for Nonoperating Interest
  1. Drilling for an interest in the property many times includes the receipt of an interest in property other than the property being drilled. Rev. Rul. 77–176, 1977–1 CB 77 provides the income tax treatment for the taxpayers in this type of drilling "deal."

    Example:

    Taxpayer A owns the entire working interest in a 640-acre oil and gas lease. Taxpayer A is willing to transfer to Taxpayer B the entire working interest in a 40-acre drill site and 50 percent of working interest in the remaining 600 acres if Taxpayer B will drill and equip a well on the 40-acre site free of all costs to Taxpayer A and allow Taxpayer A to retain a 1/16 overriding royalty interest in the 40-acre tract. After Taxpayer B successfully drilled and equipped the well as a producer, Taxpayer A assigned the working interest to Taxpayer B as agreed.
    Taxpayer A has a taxable event on the transfer of the property outside the 40-acre drill site to Taxpayer B. Taxpayer A is treated as having sold 50 percent of working interest to Taxpayer B at its fair market value and having paid the cash proceeds to Taxpayer B as consideration for the drilling of the well on the 40 acre drill site. The nature of the gain or loss on the sale will depend on the length of time the property was held by Taxpayer A and if it was held primarily for sale to customers in the course of Taxpayer A's trade or business. "A" must capitalize to Taxpayer A's 1/16 overriding royalty interest the fair market value of the 50 percent of the working interest sold. "A" has two separate properties, the 1/16 overriding royalty on the 40 acres and 50 percent of the working interest on the 600 acres.
    Taxpayer B has an entirely different tax consequence. Since Taxpayer B received the entire working interest in the 40-acre drill site, Taxpayer B can deduct all the IDC. Taxpayer B is also entitled to all the depreciation on the capitalized tangible equipment. Taxpayer B has two separate properties on the assignment of the 40-acre and the 600-acre oil and gas leases. Since the assignment of 1/2 of the working interest in the 600 acres outside the drill site is a transfer of property to which no development contribution was made, the drilling done by Taxpayer B on the drill site does not represent a capital investment in the development of the non-drill site property. Therefore, the 50 percent of the working interest in the 600 acres represents gross income to Taxpayer B to the extent of its fair market value at the date of transfer.

Bottom-Hole and Dry-Hole Contributions
  1. In the examination of intangible drilling and development expenses, certain unusual arrangements between working interest owners can be found.

    Example:

    Taxpayer A owns the entire working interest in an oil and gas lease and wants to drill a well on owned unproven property. The information Taxpayer A obtains from drilling the geologic formations can be very useful to lease owner Taxpayer B who owns the oil and gas lease adjoining Taxpayer A. Taxpayer B agrees to pay $30,000 to Taxpayer A toward the cost of the drilling of a well on Taxpayer A's property to a total depth of 8,000 feet. Taxpayer B is willing to do this because the information obtained from drilling the test well conveys productive potential of Taxpayer B'slease acreage.
    • When the total depth of 8,000 feet is reached and Taxpayer B makes the payment to Taxpayer A, Taxpayer B has made a bottom-hole contribution. Taxpayer A will be required to report the $30,000 as ordinary income. The receipt of the $30,000 bottom-hole contribution will not affect Taxpayer A's IDC or investment in equipment. One hundred percent of Taxpayer A's IDC will either be capitalized or expensed according to Taxpayer A's election under IRC 263(c). One hundred percent of Taxpayer A's investment in lease and well equipment must be capitalized. Taxpayer B must treat the payment of the $30,000 as a cost of geological and geophysical information. See IRC 167(h) and IRM 4.41.1.2.2.3.2.

  2. In the example above, the $30,000 was payable by Taxpayer B to Taxpayer A regardless of the results of drilling the well, assuming that a depth of 8,000 feet was reached. However, frequently Taxpayer B will agree to pay Taxpayer A the $30,000 only if the well is plugged and abandoned as a dry hole. The tax treatment of bottom-hole contributions and dry-hole contributions is exactly the same.

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

  2. Refer to IRM 4.41.1.2.3.6 for acquisition of offshore government oil and gas leases.

  3. Offshore development requires structures, equipment, facilities, and wells that are specially designed to operate in a marine environment.

Offshore Platforms
  1. Offshore platforms have been used for over 65 years since the first specifically designed structure was installed in the Gulf of Mexico in 1947 in a water depth of 20 feet. The industry is now capable of installing platforms in water depths of several thousand feet. Two of the largest combination drilling and production platforms in the world are located in the Gulf of Mexico. The improved techniques of fabrication and erection developed for use on Gulf of Mexico structures have influenced construction worldwide.

  2. It is not economical to use fixed-jacket platforms to produce oil and gas from water depths greater than 800 feet. Instead, deepwater platforms are typically floating and employ either a semi-submersible or "spar" design that requires mooring lines to hold it in place.

Offshore Drilling Rigs and Mobile Offshore Drilling Units
  1. Offshore drilling rigs that are installed on platforms are generally similar to drilling rigs used on land. In many circumstances it is more practical to drill wells from a "Mobile Offshore Drilling Unit" (MODU). Certain MODUs can drill and complete wells in water depths approaching 10,000 feet. The principal types of MODUs are:

    1. Semi-submersible. This MODU is an integrated unit of large dimensions consisting of tubular hulls or pontoons on which are mounted cylindrical columns supporting a fixed upper deck which serves as the drilling platform for the drilling rig. In deep water, the unit is operated from a floating but "semi-submerged" position in which the lower hull assembly is about 40 feet below the water surface. The unit is held in the drilling position by a number of large anchors and heavy chains. In shallow water, the unit can operate as a "semi-submersible" with the lower hull sitting on the bottom. It is not self-propelled and must, therefore, be towed to the drilling location.

    2. Jack-up drilling rig. This MODU has legs which are carried generally above the water when the unit is towed. When in use, the legs are lowered until they reach the bottom and penetrate the ocean floor, thereby permitting the hull to be lifted up by the legs until it becomes stationary above the surface of the water. The hull then serves as a drilling platform. This unit is not self-propelled.

    3. Self-propelled marine drilling rig. Sometimes called a "drillship" , this drilling rig is self-propelled. It has crew living quarters which are located on deck behind the drill. Below deck space is entirely taken up with drilling equipment, anchors, and other types of machinery. Modern drillships are held in location by thrusters instead of mooring lines.

Platform Construction Costs
  1. In general, construction of platforms involves three stages:

    1. Design Phase. During this phase engineers design specifications peculiar to each platform and its planned location.

    2. Land Phase. Prefabrication of as much of the platform as possible occurs on land.

    3. Marine Phase. The platform in its component form is towed by a barge to the drill site, where it is assembled and erected in place.

  2. The marine phase requires specialized construction equipment such as a combination derrick and pipe laying construction barge. These are constructed in two types. The semi-submersible drilling barge, on which is mounted a heavy lift crane instead of a drilling rig, is used in constructing offshore platforms and other production facilities. The barge also contains equipment necessary for the laying of large diameter pipelines on the ocean floor. The second type of surface floating barge performs the same functions as a semi-submersible barge but is constructed with a flat bottom and works in a floating, rather than a submerged, position. This unit is likewise not self-propelled.

  3. The examination of IDC may reveal that costs applicable to platform construction and erection have been included in IDC. The agent should obtain the services of an engineer for assistance in the examination of proper treatment to be awarded platform construction costs.

  4. An offshore platform may structurally support a drilling rig that is used to drill some or all of the wells that produce to the platform. If the production equipment is located on an adjacent platform, the platform supporting the rig is called a drilling platform. The intangible costs associated with a drilling platform can be deducted as IDC. If the platform supports the rig and contains the production equipment it is called a "dual purpose" platform. The cost of dual purpose platforms is discussed in Rev. Rul. 89-56, 1989-1 CB 83.

  5. Platforms that do not structurally support a drill rig during the drilling phase of an offshore development are referred to as production-only platforms, or simply production platforms. Generally the cost of a production platform should be recovered via depreciation.

Platform Costs Litigation
  1. In Exxon Corp. v. U.S., 547 F.2d 548, 39 AFTR 2d 442 (Ct.CI. 1976) the court considered costs incurred in the fabrication of "templet type" platforms. The court held that the cost for labor, fuel, repairs, supplies, and hauling incurred in fabricating the standardized components were eligible for IDC option to expense.

  2. In 1981, the tax court considered similar issues in Standard Oil Co. v. Commissioner, 77 TC 349 (1981) with respect to jacket type platforms, and in Texaco Inc. v. United States, 598 F.Supp. 1165 (S.D. Texas 1984) and Gulf Oil Corp. v. Commissioner, 87 TC 324 (1986), 54 AFTR 2d 6308 (SD Tex 1984) the courts considered several different types of offshore platforms which were designed and constructed for use at specific platform locations. And the court held that the platform or components were not items "ordinarily" considered salvageable.

  3. In view of these decisions, the Service decided it would no longer follow Rev. Rul. 70–596, 1970-2 CB 68 which held that all expenditures incurred in the onshore fabrication of offshore drilling and production platforms are ineligible for IDC expense. Rev. Rul. 89–56, 1989–1 CB 83 held that the deductibility of expenditures related to the onshore fabrication of offshore drilling and production platforms as IDC would be determined on a platform-by-platform basis depending on whether the platform is customized for a specific drill site or salvageable.

  4. In LL&E v. Commissioner, 102 T.C. 21 (1994), the IRS argued that production equipment located on a dual purpose platform that was used in drilling operations for a short period of time was ineligible for IDC expense under a "primary purpose" test. The Tax Court determined that the primary purpose test did not exist and that all equipment used in drilling is generally eligible for IDC expense. The IRS acquiesced in the court's decision. See AOD, IRPO 51,058, Louisiana Land and Exploration Co. v. Commissioner, Basis for Cost Depletion, File No. AOD/CC-1995-008 (August 7, 1995).

Each Platform Analyzed Separately
  1. Design and fabrication expenditures may be treated as IDC if the evidence shows the following:

    1. The platform in question is incident to and necessary for the drilling of wells even though it is subsequently used for production.

    2. The platform is designed and constructed for use at a specific site.

    3. And platforms of that type are not ordinarily used or otherwise salvaged as a unit.

  2. When a platform is determined to be eligible for IDC treatment, an analysis of the salvageability of its structural components and subcomponents may be required. For example, the onshore fabrication cost of a standardized and reusable compressor package is not subject to IDC treatment simply because it will be installed on a platform and used in drilling operations but if the package is further integrated into a larger unsalvageable component or the platform itself, both the original fabrication costs and the additional costs involved in the integration will likely qualify for IDC treatment.

  3. The most significant references applicable to costs of acquiring, transporting, and erecting offshore platforms in connection with oil and gas properties can be found in IRC 263(a) and (c), Treas. Reg. 1.612–4; Rev. Rul. 89–56, the decision in Exxon Corporation v. United States; Louisiana Land and Exploration Co. v. Commissioner , 102 TC 21 (AOD, IRPO 51,058, Louisiana Land and Exploration Co. v. Commissioner, Basis for Cost Depletion, File No: AOD/CC-1995-008,(August 7, 1995); GCM 37359; and GCM 39085.

  4. The issue of which particular costs incurred to construct and install offshore platforms are IDC has been ongoing since the 1970's. The examination of IDC may reveal that costs applicable to platform construction and erection have been included in IDC. Examiners should request engineer assistance in the examination of proper treatment to be awarded platform constructions costs. The Action on Decision in Louisiana Land and Exploration Co. v. Commissioner should be reviewed by the engineer.

  5. With respect to platform dismantlement or well plugging, examiners should also review IRM 4.41.1.3.2.9.

"Subsea Wells" and Deepwater Platforms
  1. Significant advances related to Mobil Offshore Drilling Units (MODUs), floating offshore platforms, and "subsea" wells and related infrastructure have permitted the economical production of oil and gas from deepwater locations in the 21st century, especially in the Gulf of Mexico. Modern MODUs can drill and complete wells in water depths approaching 10,000 feet. These wells are extremely expensive to drill and (if successful) to complete. Because intervention in these wells is also very expensive, the operator conducts extensive tests of the mechanical systems of the well before the MODU is released.

  2. A key characteristic of a subsea well is that its wellhead (aka "christmas tree" ) is located on the seabed (a "wet tree" ) instead of being located on an offshore platform (a "dry tree" ).

  3. Subsea flow lines carry production from the subsea well to processing equipment located on a platform. Subsea control cables, which are known as "umbilical lines" , connect the subsea well to a control center located on the platform. The distance between wells and the platform may be 20 miles or more. Technological advances have made it feasible in certain situations to install equipment near the subsea wells such as separators, booster pumps and water injection pumps. Remotely operated underwater vehicles (ROVs) are used to carry out the work of connecting the wet trees, lines, and equipment packages.

Issues with Subsea Wells and Deepwater Platforms
  1. The costs of subsea wells and deepwater platforms are usually examined by IRS engineers. One issue involving the long-term use of a MODU illustrates the complexity:

    Example:

    An oil company makes a large payment to a drilling contractor to modify a MODU so that it can carry out certain tasks when drilling wells for the oil company. The oil company contracts to use the modified MODU for a number of years under typical commercial terms. The oil company improperly deducts the payment for modifications as IDC. The payment should be amortized over the life of the contract to use the modified MODU because the contract is an intangible asset. If the oil company acquired equipment to be used for drilling it would recover the cost via depreciation.

  2. Examination issues involving IDC deductions are summarized as:

    1. Intangible costs, such as those incurred for design, fabrication, and installation of subsea flowlines and umbilicals are often deducted as IDC by taxpayers. Their basic premise is that initial production of a subsea well from the seafloor to the processing equipment located on a platform is analogous to the "flow tests" which were conducted by the operator in the Louisiana Land and Exploration Co. v. Commissioner case cited in IRM 4.41.1.2.4.9.5. The intangible cost of production equipment used in those flow tests was found to be deductible as IDC. To understand how subsea assets are generally distinguishable from the equipment described in the LL&E case, and not treated as IDC, it is useful to review why the court reached its conclusion.

    2. In Louisiana Land and Exploration Co. v. Commissioner, the flow tests were conducted as part of the completion operation for each well. The wells had been perforated in stages and after each stage was added, the well was flowed (produced) for several hours to determine if the desired production rate was achieved. Only then did the operator shift drilling and completion work to another well. Permanent production equipment had been used to conduct the flow tests. The court determined the subject equipment was incident to and necessary for the development of wells, and therefore was allowable as IDC. The IRS acquiesced and no longer argues that the primary use of equipment in production operations negates the fact that it was used in the development of wells.

    3. IRS engineers have not found a situation where the subsea flowlines, umbilicals and production equipment were utilized in the same manner as the equipment in the Louisiana Land and Exploration Co. v. Commissioner case. Rather, the productive capability of modern deepwater wells is normally verified by analyzing data from seismic surveys, numerous well logs, pressure measurements and rock and fluid samples retrieved by sophisticated sampling tools lowered into the well from the MODU. In circumstances where additional confirmation is needed, the operator will produce the well to portable flow test equipment located on the MODU. The well may be temporarily abandoned at this point to allow analysis of the data and design of completion assembly. Regardless, a MODU will be utilized to perform all of the final completion operations, including installation of the subsea tree before leaving the location.

    4. Typically, operators will assign responsibility of a subsea well to a specific internal group depending on the status of the well. Examples of such groups include the drilling and completion team, the flowline and umbilical installation and hookup team, the well and facilities start-up team, and finally the production operations team. The transfer between groups is usually accompanied by certain documents (generally known as pre-commissioning reports, commissioning reports, or "hand-off packages" ). Inspections of those documents have shown that the wells are generally viewed by the operator as being "completed" and "ready to produce" prior to initial production to the platform.

    5. A review of operators' press releases and official SEC filings show that prior to initial production of subsea wells it is not uncommon for the wells to be referred to as "successful" , for operators to have expended very considerable sums to construct an offshore platform, and for significant quantities of proved reserves to be recorded. The latter is especially significant since reservoirs are only considered proved when production of oil and gas in economic quantities using existing operating methods is known or reasonably certain.

    6. In summary, intangible costs surrounding subsea flowlines, umbilicals, production equipment, and production platforms are not deductible as IDC. The entire cost should be recovered by depreciation starting in the year they are placed in service. When conducting a risk analysis, examiners should take into account the effect of bonus depreciation and be mindful that the issue surrounding these costs and placement of assets often span multiple years.

Production and Operation of Oil and Gas Properties

  1. This section provides guidelines on the production and operation of Oil and Gas Properties.

  2. Oil and gas production is the ultimate objective of acquiring rights to an oil and gas property. The drilling and completion of a well is necessary before an oil and/or gas property enters its production stage.

  3. "Production and Operation" means the day-to-day activities necessary for the production and sale of crude oil and/or natural gas. Oil is produced from the wells either by natural pressure in the reservoir or by "artificial lift." "Artificial lift" usually consists of installing a regular plunger and sucker rod-type pump in the well. However, it can also be accomplished by use of "gas lift" or by hydraulic pump. The operation of an oil and/or gas lease involves the use of lease and well equipment. The operation requires expenditures for and the use of utilities, power, labor and supplies. Except for the integrated producer, the oil and/or gas produced is usually sold to a larger integrated operator who transports it to his/her facilities by pipeline. Oil sometimes is sold to a trucking company which resells it to a refiner.

  4. The accounting and income tax implications involving oil and gas are often complicated by the fact that drilling and completion activities are continuing on the same property that contains production operations.

  5. An understanding of the typical operation will aid in the discussion of the auditing techniques dealing with each type of interest owner.

  6. Basically, there are two types of interests in oil and gas properties: operating and nonoperating. The most common types of interests are also described as working interests and royalty interests. See Exhibit 4.41.1-2. The distinct difference is that the working interests bear all the operating costs of the property. The royalty interests are free of all operating costs except taxes. There may be several royalty interest owners and working interest owners in a single oil and gas property.

  7. The owners of the working interest in an oil and gas property will designate one of the working interest owners as the "operator;" or they may designate someone who does not own an interest in the property as the operator. The operator is responsible for the physical operation of the oil and gas wells.

  8. Typically, the operator will own an interest in the property, but it is not necessary. The operator is usually someone experienced in the operation of oil and gas properties. The operator performs the necessary functions to produce the oil and gas and bills the working interest owners for their proportionate share of the expense, which includes overhead and a profit factor for the operator. Royalty owners do not pay any expense except for production taxes and ad valorem taxes. However, some states allow an operator to bill the royalty owner for its share of certain "post production" costs such as the cost to compress the gas so that it can be sold to a pipeline purchaser.

  9. In some cases, the working interest owners will allow the operator to sell their share of the production, deduct their share of the expense of operation, and remit the net amount due them. Refer to IRM 4.41.1.3.2.6 Joint Billing, where, depending on the circumstances, a question may arise as to whether or not this arrangement may be an association taxable as a corporation. Otherwise, the purchaser of the production remits the owner's share directly and the operator bills the working interest owner for its share of the lease operating expenses.

  10. Regardless of the method of settlement between the operator and the working interest owners, the operator sends out information, usually in the form of a detailed statement of each item of expense, equipment and revenue, that relates to the property on a monthly basis. The owner's share will be computed on this statement. Royalty owners are usually paid directly by the purchaser of the production.

  11. The typical operation described above is very simplified. Each operator will conduct operations slightly different. Suggestions to help the examiner identify and develop areas are described in the following sections.

Sale of Oil and Gas

  1. Underreporting of the proceeds from oil and gas sales is facilitated by the practice, common in the industry, of assigning the income from proven properties as collateral on loans and paying the oil runs directly to the lender. Another problem is the sale of production payments and having a percentage of the oil and gas sales proceeds paid directly to the owner of the production payment. The following sections describe various types of problems that may be encountered and suggested auditing techniques for determining the correct income to be reported from oil and gas sales. See Exhibit 4.41.1-11.

Income to Royalty Owner
  1. Income from oil and gas royalties is passive-type income derived from the landowner's royalty, overriding royalty, or a net profits interest. This type of income bears none of the burden of operations or development except taxes and any "post production" costs that state law allows an operator to charge a royalty owner in order to make the production marketable, such as for gas compression. Royalty income may be paid by the operator of the property or by the purchaser of the crude oil or gas production. In either event, the royalty owner should receive a statement with the check (usually monthly but at least periodically) showing the total sales of oil and gas from the property, interest in the property, and the amount of production. Taxpayer will normally report royalty income on Schedule E as rents and royalties or from flow through entities. The taxpayer can have both royalty and working interest income and report both on a Schedule C.

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

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

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

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

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

  7. If the taxpayer assigned all income, deducted tax liability is available.

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

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

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

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

    1. Leases that continue to operate at a loss and no drilling or development is being done

    2. Income from the property is not representative of the expense being incurred

    3. Large intangible development costs are being incurred but indications of the property being transferred before the income is realized

      Example:

      Transferred to a trust or other family member.

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

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

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

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

  9. If a taxpayer is incurring large intangible development costs on properties to get them to the production stage and then making a practice of transferring them to family members or trusts, it may be that this practice can be attacked under IRC 183 as not being engaged in business for a profit or under IRC 671 through 678 as an assignment of income.

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

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

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

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

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

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

  3. Since the revenue relating to the production payment may be forwarded directly from the first purchaser of the production to the owner of the production payment, it is difficult to discover the existence of one without special tests being conducted. It a production payment exists, and the property is sold during the year, the sale is encumbered by the existence of the payment, similar to the assumption of a mortgage.

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

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

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

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

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

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

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

    1. Is not pledged for use in the future exploration or development of the property or properties which are burdened by the production payment

    2. May be used for the exploration or development of any other property, or for any other purpose than that described in (a) above

    3. Does not consist of a binding obligation of the payee of the production payment to provide services, materials, supplies, or equipment for the exploration or development described in (a) above

    4. Does not consist of a binding obligation of the payee of the production payment to pay expenses of the exploration or development described in (a) above

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

    1. The development must relate to the property burdened by the production payment.

    2. The proceeds must be used for exploration and development, not for the production of minerals. The Regulations indicate that one of the tests that should be applied is whether or not there has been any prior production from the mineral deposit burdened by the production payment. If there has been production, it may not meet the exception of Treas. Reg. 1.636–1(b) as production payment pledged for development.

    3. Repayment of the production payment must be only from the property involved and not from other leases or by a guaranty letter. See Brountas v. Commissioner, 73 T.C. No. 42 (1979).

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

    Example:

    On wildcat (untested) leases, reserves (if any) are not known. Any future wells drilled may be dry holes. Treas. Reg. 1.636–3(a) states that a production payment "right to a mineral in place has an economic life of shorter duration than the economic life of a mineral property burdened thereby."

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

Operating Expense

  1. There are three phases of activity referred to in the oil and gas industry involved in attaining production of minerals:

    • Acquisition of the mineral property

    • Exploration and development

    • Operation

  2. Each of these three phases requires the expenditure of funds, and different tax treatment is accorded each.

    Example:

    Acquisition costs of a mineral property must be capitalized. However, the taxpayer may elect to capitalize or expense IDC incurred during the exploration and development phases. Operating expenses are taken into account in accordance with the taxpayer's method of accounting. It is important, therefore, to be able to distinguish or categorize the various expenditures that will be encountered in an oil and gas producer's return.

  3. Operating expenses of an oil and gas lease will include both direct and indirect expenses and depreciation. It is essential that expenses be segregated by property in order that the taxable income of each one can be determined if the income from the property is subject to percentage depletion.

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

Operating Expense vs. Intangible Development Costs (IDC) vs. Capital
  1. Even though the majority of taxpayers elect to currently deduct IDC, it is still necessary to be able to distinguish between operating expense, IDC, and capital expenditures.

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

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

    1. The bonus paid to the landowner

    2. Commissions paid if acquired through a broker

    3. Abstracting costs

    4. Attorney fees for title opinion and for drafting instruments of agreement or conveyance

    5. Landman or land department expenses

    6. Transfer fees and taxes. If geological and geophysical expenditures are instrumental in the lease being acquired or retained, they are also required to be capitalized. However, see IRC 167 regarding amortization of geological and geophysical expenditures for tax years beginning after the enactment of the Energy Tax Incentives Act of 2005.

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

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

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

    Example:

    The fracturing of the producing sand with nitroglycerine before being placed in production and the cleaning out of the well.

    1. Refer to P-M-K Petroleum Co. v. Commissioner, 24 B.T.A. 360 (1931); rev'd, 66 F.2d 1009 (8th Cir. 1933); 12 AFTR 1335. The deepening of an existing well was held to be intangible development costs in Monrovia Oil Co. v. Commissioner, 28 B.T.A. 335 (1933); aff'd on another issue, 83 F.2d 417 (9th Cir. 1936); 17 AFTR 978; 36–1 USTC 521.

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

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

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

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

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

  12. See Exhibit 4.41.1-10 for items to consider during preparation of Forms 4318, 4764, 4764-Bs, and 886As.

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

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

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

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

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

    1. Allocated among the several mineral properties based on the gross income from the property

    2. Allocated among the several mineral properties based on the direct expenses of each (preferred method). See Exhibit 4.41.1-9.

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

Depreciation
  1. Treas. Reg.1.611–5 provides a reasonable allowance for depreciation of improvements made to oil and gas wells. The deduction allowed under IRC 611 is determined under IRC 167.

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

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

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

  5. In the computation of depreciation under the unit of production method, using the proper oil and gas reserves and a reasonable estimate of salvage value is important. Examiners should verify that estimated salvage value is reflective of the taxpayer's experience with disposing of retired assets. Joint operating agreements between working interest owners may include an agreed-upon method to determine salvage value when assets such as pumping units are retired and the operator takes physical and legal possession of them. If a dispute arises, an IRS engineer may need to be consulted.

  6. Examiners may find that taxpayers are improperly reducing the estimated salvage value of their assets by up to 10 percent of the basis of the assets. Regulations 1.167(a)-(1) and 1.167(f)-1 suggest this is allowable, but the underlying code provision, IRC 167(f) was repealed several years ago and the regulations have not yet been revised.

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

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

  9. It should be relatively easy to determine if a taxpayer is using the unit of production method of depreciation. The instructions for Form 4562, Depreciation and Amortization (Including Information on Listed Property), state that depreciation which is computed by that method should be entered on Line 15 and a separate sheet with certain information attached.

Placed-in-service date of wells
  1. Expenditures for the steel casing and associated downhole equipment must be capitalized. Refer to Rev. Rul. 78-13, 1978-1 CB 63. These items are placed in service and are subject to depreciation when an oil or gas zone is found, and the well completed and made capable of production. If an oil or gas zone is not found (i.e., a nonproductive well was drilled), those assets are not placed in service and are not subject to depreciation. The adjusted basis of that portion of the casing and associated downhole equipment left behind in the well is deductible as a loss under IRC 165 and the associated regulations.

  2. The ruling does not state that equipment such as separators, storage tanks or a pipeline must be available to accept production for a well to be considered placed-in-service. Oil and gas wells may stand idle for a period of time while such assets are being constructed by the taxpayer or by third parties such as a pipeline company.

MACRS Class Lives and Recovery Periods
  1. Refer to Exhibit 4.41.1-43 which compiles the MACRS class lives and recovery periods for assets used by companies in the various business segments of the oil and gas industry. The majority of the information is from Rev. Proc. 87-56, IRB 1987-2 CB 674.

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

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

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

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

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

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

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

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

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

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

Future Liabilities for Well Plugging, Platform Dismantlement, and Property Restoration
  1. The operator of an oil well or an offshore platform is obligated by regulations and/or its lease to perform certain tasks when its assets reach the end of their useful lives. Wells must be plugged and abandoned. Any earthen pits that contained waste products from drilling or production operations must be either sealed or emptied. Offshore platforms must be removed so they don’t become a hazard to navigation. The term "dismantlement, removal and restoration" (DR&R) is often used to encompass all of these obligations.

  2. For financial accounting purposes, public companies must estimate the amount of their future DR&R obligations and make appropriate entries on their financial statements. As evidenced by Rev. Rul. 80-182, 1980-2 CB 167, the Service’s long-standing examination position is that "estimated future" DR&R costs may not be deducted (i.e., a deduction is only allowed when the DR&R activity takes place).

  3. As background, in the 1970's and 1980's the Service’s position was successfully challenged by a number of mining companies. In response, IRS Appeals created a coordinated settlement position which allowed 25-year amortization of estimated DR&R costs for domestic offshore platforms located in water depths of less than 500 feet and placed in service before mid-1984. Similarly, amortization of the estimated DR&R liability of the Trans-Alaska Pipeline was allowed for its original owners. See United States v. ConocoPhillips Co., 2012 U.S. Dist. LEXIS 119339, 110 A.F.T.R.2d (RIA) 5628, 2012-2 U.S. Tax Cas. (CCH) P50535 (N.D. Okla. 2012). Such settlements generally require the "restoration to income" of previously amortized amounts in two circumstances:

    • when the taxpayer is relieved of the DR&R liability (e.g., by sale of the asset)

    • when DR&R actually takes place and the taxpayer incurs out-of-pocket costs

  4. The Service’s position as reflected in Rev. Rul. 80-182 was essentially codified with the enactment of the Economic Performance rules of IRC 461(h) in 1984. Since DR&R is normally performed by service providers, IRC 461(h)(2)(A) would permit a deduction only when DR&R services are performed. However, examiners should be aware of the following potential issues:

    1. Taxpayers improperly recovering (over time) estimated DR&R costs via additions to basis for depletion, depreciation, or amortization. Examiners should make sure the taxpayer has reversed out all such deductions or basis additions that were included or expensed for financial accounting purposes.

    2. Taxpayers failing to properly "restore to income" any previously amortized amounts at the time the DR&R actually occurs or when they are relieved of the liability.

    3. Deducting the full amount of premiums paid for surety bonds when part of the premium is essentially a refundable deposit for future DR&R. Surety bonds are often required of "thinly capitalized" oil companies that install offshore platforms in federal waters. Annual insurance premiums are generally deductible. However, some surety arrangements consist of both a surety policy and an escrow account. Contributions to an escrow account are generally not deductible because they are refundable if the policy is cancelled.

    4. "Guarantee fees" paid to a foreign parent. The U.S. Department of Interior will generally impose the DR&R obligation on the original lessor of federal land whenever a sublessor fails to perform its obligation. Consequently, the transferor of a federal oil and gas lease will often require (by contractual obligation) the transferee to maintain adequate financial reserves to perform DR&R, or to obtain the guarantee of a parent corporation. Examiners may find U.S. taxpayers improperly deducting "fees" paid to their foreign parent to "guarantee" performance of DR&R on behalf of its subsidiary. Such payment should not be allowed as a deduction because in substance it represents a mere deposit of funds with the parent corporation.

  5. Economic performance rules for liabilities that are assumed in the sale of a trade or business are specifically addressed by Treas. Reg. 1.461-4(d)(5). If the buyer expressly assumes the liability in the sale of trade or business that the seller but for the economic performance requirement would have been entitled to incur as of the date of the sale, economic performance with respect to that liability occurs as the amount of the liability is properly included in the amount realized by the seller upon the sale. If an examiner determines that a taxpayer utilized this regulation in the context of selling assets subject to future DR&R liabilities, then the liabilities should be reviewed and discussed with Local Counsel or a Subject Matter Expert.

Secondary and Tertiary Recovery Methods

  1. The production of crude oil from a reservoir is often viewed as occurring via recovery methods that occur in phases (e.g., primary, secondary and tertiary recovery methods).

    • Primary recovery relies on the inherent energy in the reservoir to allow wells to produce fluids in the reservoir to the surface, and pumps to lift fluids from those wells when the reservoir energy is insufficient

    • Secondary recovery methods generally involve the injection of water or natural gas into the reservoir to increase or maintain its pressure, or to displace oil towards producing wells without causing significant chemical or physical changes to the oil

    • Tertiary recovery methods generally cause a significant chemical or physical change to the oil (other than just an increase in pressure). An example is the introduction of heat into the reservoir in order to lower the viscosity (thickness) of the oil which in turn allows it to more readily flow towards producing wells. "Tertiary recovery" is a term that has been used in the industry for several decades. IRC 193 contains a definition that is specific to incentives in the Code and references qualified tertiary recovery methods such as

    • Miscible fluid displacement

    • Steam drive injection

    • Microemulsion or micellar/emulsion

    • In situ combustion

    • Polymer augmented waterflooding

    • Cyclic steam injection

    • Alkaline (or caustic) flooding

    • Carbon dioxide augmented waterflooding

    • Immiscible carbon dioxide displacement

    • Any other method to provide tertiary enhanced recovery which is approved by the secretary for purposes of IRC 193

  2. The use of horizontal drilling in conjunction with reservoir fracturing has become very common in recent years and has resulted in very significant production of oil and natural gas. However, those are drilling and completion techniques that allow the production of oil and gas via primary and other recovery methods.

  3. Secondary and tertiary recovery methods of oil recovery may be instituted at any time during the economic life of an oil field. The implementation usually occurs after the entire field has been developed and primary recovery has occurred for a number of years. Information gained during development and production operations is very important in optimizing the design of subsequent recovery methods.

  4. A successful secondary or tertiary recovery program involves a plan wherein water, gas, or some other fluid will be injected into the oil bearing formations and force the oil into the bore holes in order that it may be pumped out. This may involve the drilling of injection wells and additional oil wells. The injection wells may be located on the perimeter of or interspersed in a pattern throughout the oil field in order to drive the oil through the formation to the oil wells. Because of the need for a plan involving an entire field, several owners may be involved. Hearings before the state conservation commission are likely to be required to gain approval of the plan. Unitization of ownership interests will also likely be required.

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

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

  3. Another common secondary recovery method is the injection of natural gas into an oil reservoir in order to maintain reservoir pressure which in turn improves oil recovery. See IRM 4.41.1.3.9.7 for potential issues.

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

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

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

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

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

  3. There are two resources that may help the examiner identify or discover that a water supply well or salt water disposal well has been drilled. If the taxpayer is an operator, an oil field map identifies the location and number of all wells. Usually, fresh water wells and salt water disposal wells can be identified from such a map. In addition, most state regulatory agencies require a permit to be secured before the well can be staked and drilling started in which case the operator would have a copy of the application, giving all of the information needed for a determination of the type of well drilled.

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

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

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

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

  4. Examiners should be aware that some taxpayers have improperly claimed that the capital cost of tangible equipment which handles tertiary injectants (such as carbon dioxide pipelines) is currently deductible under IRC 193 as a tertiary injectant expense. Taxpayers' position is primarily based on language found in Rev. Rul. 2003-82, 2003-2 C.B. 125, which was issued with respect to the IRC 43 Enhanced Oil Recovery tax credit. That ruling states that for purposes of IRC 43(c)(1)(C), the definition of "qualified tertiary injectant expenses" includes expenditures related to the use of a tertiary injectant as well as expenditures related to the acquisition (whether produced or acquired by purchase) of the tertiary injectant. However, the ruling did not extend the definition beyond costs which would be deductible expenses. The day-to-day cost to operate a CO2 pipeline can constitute an IRC 193 tertiary injectant expense, but not the capital cost of the pipeline. The Service's reasoning is explained in PLR 201117028.

Enhanced Oil Recovery Tax Credit

  1. IRC 43 was enacted in 1990 to provide an investment credit for certain costs paid or incurred with respect to qualified Enhanced Oil Recovery (EOR) projects. The amount of the credit is generally equal to 15 percent of qualified expenditures made by the taxpayer and becomes part of the general business credit. The credit is claimed on IRS Form 8864.

  2. The EOR credit has a "phase out" provision that will reduce or eliminate the rate of the credit whenever oil prices in the U.S. rise above $28 per barrel (adjusted for inflation after 1990). IRS Notice 2013-50, IRB 2013-32 IRB 134 explains that:

    • No "phase-out" occurred in calendar years 1991 through 2005

    • 100 percent "phase-out" occurred in 2006-2013

  3. Generally, the EOR credit is only available for projects that employ certain tertiary recovery methods, unless the IRS approves an additional recovery method via a revenue ruling or a private letter ruling. The projects must be located within the U.S. and have commenced after December 31,1990. There is an exception for "significant expansions" of projects that began before 1991.

  4. Starting in 2005 the EOR credit was extended to costs to construct a gas treatment plant capable of processing certain Alaska natural gas for transportation through a pipeline with a capacity of at least two trillion BTU of natural gas per day. To qualify, the gas treatment plant must also produce carbon dioxide which is injected into a hydrocarbon-bearing geological formation.

  5. A self-certification process is mandated by the statute. The operator of each EOR project (or its designee) must file a certification from a registered petroleum engineer stating that the project meets certain criteria. Afterwards, a continuing certification is filed annually. IRS Form 8864 directs taxpayers to file all certifications with the Ogden Campus. The petroleum technical subject matter experts are responsible for maintaining the inventory of the certifications. When a certification appears to lack information required by the regulations, the technical subject matter experts will notify the examination team for taxpayers under continuous audit, and will directly contact other taxpayers.

  6. The expenditures which will qualify for the IRC 43 tax credit generally consist of tertiary injectant expenses, tangible property costs, and intangible drilling costs (IDC). For purposes of the EOR credit, tertiary injectant expenses must be described in IRC 193 and deductible during the taxable year under any code section. Refer to Rev. Rul. 2003-82, 2003-2 CB 125. The at-risk limitation rules of IRC 465 apply. On a year-by-year basis taxpayers may decide whether or not to claim the credit. When the credit is claimed, the taxpayer must reduce its deductions and/or basis of those items which comprise the qualified expenditures by the amount of the credit.

  7. Many EOR projects are operated by joint ventures and the operator will frequently notify the non-operators as to the annual expenditures for qualified costs. When an examiner has reviewed a project in sufficient detail to determine the merits of the project and the associated major expenditures, the following steps should be taken:

    • Secure the identity of the operator, each working interest owner, and the working interest percentage of all parties

    • Request a copy of any information letter supplied to or from the operator regarding the amount of qualified costs

    • Provide the forgoing information and a synopsis of the examiner’s determination to the petroleum technical subject matter experts who are responsible for forwarding the examiner's determination to the other examination teams for their consideration.

  8. The Enhanced Oil Recovery Tax Credit is no longer a tier issue per LB&I Directive 4-0812-010.

  9. Reviewing the qualification of an EOR project or the associated costs requires specialized knowledge of petroleum operations. Agents should consider requesting the services of a petroleum engineer.

IRC 45Q Credit - Sequestration of Carbon Dioxide in Enhanced Oil or Natural Gas Project

  1. A recently added General Business credit, IRC 45Q, provides a tax credit for qualified carbon dioxide (CO2) that is captured and disposed of in secure geological storage (sequestered). Generally, the credit is allowed to the entity or person that captures and physically or contractually ensures the disposal of the qualified CO2.

  2. The credit rate is:

    • $20 (adjusted for inflation for tax years beginning after 2009) per metric ton for qualified CO2 captured at a qualified facility, disposed of in secure geological storage, and not used as a tertiary injectant in a qualified enhanced oil or natural gas recovery project (EOR project); and

    • $10 (adjusted for inflation for tax years beginning after 2009) per metric ton for qualified CO2 captured at a qualified facility, disposed of in secure geological storage, and used as a tertiary injectant in an EOR project.

  3. For the purpose of calculating the credit, a metric ton of CO2 includes only the contained weight of the CO2. The weight of any other substances, such as water or impurities, is not included in the calculation. Only CO2 captured and disposed of, or used as a tertiary injectant within the United States or a U.S. possession and later disposed of in secure geological storage, is taken into account.

  4. Some definitions are specific to this credit:

    • Qualified CO2 is CO2 captured after October 3, 2008, from an industrial source that would otherwise be released into the atmosphere as an industrial emission of greenhouse gas, and is measured at the source of capture and verified at the point of disposal or injection. Qualified CO2 also includes the initial deposit of such captured CO2 used as a tertiary injectant in an EOR Project. It does not include CO2 that is re-captured, recycled, or otherwise re-injected as part of the EOR Project.

    • A Qualified Facility is any "Industrial Facility" that is owned by the taxpayer where carbon capture equipment is placed in service and that captures at least 500,000 metric tons of CO2 during the tax year.

    • An Industrial Facility is a facility that produces a CO2 stream from a fuel combustion source, a manufacturing process, or a fugitive CO2 emission source that, absent capture and disposal, would otherwise be released into the atmosphere as an industrial emission of greenhouse gas. An industrial facility does not include a facility that produces CO2 from CO2 production wells at natural carbon-dioxide-bearing formations.

      Note:

      "CO2 production wells" and "natural carbon dioxide-bearing formation" have not yet been defined. Local Counsel should be consulted if the CO2 concentration of a source gas is sizeable.

    • Secure Geological Storage includes storage of the captured CO2 at deep saline formations, oil and gas reservoirs, and unmineable coal seams under such conditions as the IRS may determine under regulations.

  5. The credit is claimed on Form 8933 - Carbon Dioxide Sequestration Credit. Examiners should review the instructions to the form and also Notice 2009-83, 2009-2 CB 588. Section 6 of the Notice requires taxpayers that claim the credit to file an annual report with the IRS Office of Chief Counsel. Examiners should obtain a copy of the statement and written confirmation by the taxpayer that the information contained in the report is still correct, especially the identity of any contractually ensuring party. A referral to an IRS engineer should be considered.

  6. One attribute of a qualified EOR project is that the operator has submitted a Petroleum Engineer’s Certification to the Ogden Service Center. If the taxpayer asserts that the CO2 which it captured is being used as a tertiary injectant in an EOR project, examiners should obtain a copy of the certification and review it for pertinent facts.

  7. If a taxpayer claims the IRC 45Q credit based on the contractual assurance that another party will sequester the CO2 in secure geologic storage, a copy of the contract between the parties should be obtained and inspected to verify such assurance exists. If such assurance does not exist, but the parties are renegotiating the contract to include it, the examiner should contact local IRS Counsel for advice on how to proceed. In the event the contract does not provide appropriate contractual assurance, the tax credit should be disallowed. If any credit was claimed in previous tax years, the examiner should contact local IRS Counsel regarding recapture of those amounts.

  8. IRC 45Q and Notice 2009-83 state that a taxpayer claiming the credit must comply with evolving rules of the U.S. Environmental Protection Agency (EPA) regarding the sequestration of CO2 and reporting of CO2 volumes measured at the source of capture and verified at the point of disposal or injection.

  9. EPA promulgated final rules regarding the reporting of both CO2 emissions and CO2 use (including sequestration) for years after 2010. Subpart RR - Geologic Sequestration of Carbon Dioxide is applicable to the IRC 45Q credit. Refer to http://www.epa.gov/ghgreporting/reporters/subpart/rr.html

  10. The Preamble to EPA’s final rule states in plain language that, under the final rule, operators of facilities that are sequestering CO2 in geologic storage must comply with Subpart RR regardless of whether the CO2 is currently used as a tertiary injectant in an EOR project. EPA’s preamble also states that taxpayers claiming the 45Q tax credit after 2010 must follow Subpart RR’s "MRV procedures" . MRV stands for Monitor, Report and Verify. The MRV procedures require the operator to submit an MRV plan to the EPA for its approval, and to annually report CO2 volumes, including amounts sequestered, pursuant to the plan. Examiners should obtain a copy of these documents.

  11. Tax credits claimed by the taxpayer in years after 2010 should be reconciled with annual volumes reported by the operator of the facility to the EPA under its subpart RR rules. If a taxpayer has claimed the tax credit for current or prior years, but the operator did not submit an MRV plan to the EPA for activity for years beginning after 2010, the examiner should contact local IRS Counsel and Petroleum Subject Matter Experts regarding the treatment of those previously or currently claimed credits.

Nonconventional Source Fuels Credit

  1. IRC 29, renumbered IRC 45K and made part of the general business credit with enactment of Tax Incentives Act of 2005, authorizes an income tax credit for the production of certain non-conventional fuels. The IRC 29 credit is generally equal to $3.00 multiplied by the number of "barrel-equivalents" of qualified fuel that is produced and sold by the taxpayer to unrelated persons. When a fuel-producing property is owned by more than one taxpayer, production is generally allocated based upon each taxpayer’s interest in gross sales. Treas. Reg. section 1.761(d) provides specific rules for gas producers that produce natural gas under joint operating agreements.

  2. Qualified fuels include:

    • Oil production from oil shale and tar sands

    • Gas produced from geo-pressured brine, Devonian Shale, coal seams, tight sands, biomass, and

    • Liquid, gaseous and solid synthetic fuels from coal (including lignite)

  3. The credit for these fuels has both a drilling window (generally from 1-1-80 through 12-31-92) and a production window (from 1-1-1980 to 12-31-2002). Thus, except for production in 2002 for which a taxpayer claims a credit, this issue no longer exists after 2002.

  4. Because of the technical nature of the issue, IRC 29 credit is usually worked by the Service’s engineers.

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

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

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

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

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

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

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

    • Initial credit, and

    • A fraction equal to the amount that the "reference price for the calendar year in which the tax year begins" exceeds $23.50 ÷ $6.00. Mathematically, it can be given as follows:

      $3 - [ (Ref.Price-$23.50)/6 × $3]

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

    Calendar Year Inflation Adjustment Factor Reference Price Credit Amount (Per BOE) Credit Amount for Gas from Tight Formations (Per BOE)
    1999 2.0013 $15.56 $6.00 $3.00
    2000 2.0454 $26.73 $6.14 $3.00
    2001 2.0917 $21.86 $6.28 $3.00
    2002 2.1169 $22.51 $6.35 $3.00
    2003 2.1336 $27.56 $6.40 $3.00

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

    • A pro-rata portion of the credit generated through special financing arrangements

    • Any portion of the credit financed through grants from Federal, State or a political subdivision of state entities

    • Proceeds from state or local obligations used to finance the project if the interest from those bonds is exempt from tax under IRC 103

    • IRC 48(a)(4)(C) subsidized energy financing

    • IRC 48 energy credits

    • IRC 43 enhanced oil recovery credits

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

Monetization of IRC 29 Credits
  1. An industry practice that started in the early 1990’s was to monetize or, in effect, sell the rights to the tax credits. This is advantageous for taxpayers with substantial credits that were of no benefit to them because of their tax situation. A taxpayer in an AMT position and from future projections will be an AMT for years to come, the credits would be of marginal value. Therefore many taxpayers decided to transfer the right to the credits for cash and monetize the credit.

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

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

Typical Audit Steps
  1. Determine the IRC 29 credit claimed for each tax year.

  2. Discuss the limitations of the AMT with a technical specialist.

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

    • Well identification (name, location, and API number)

    • Producing formation

    • Type of qualified fuel

    • Volume of gas produced and sold during the year

    • Number of Btu’s claimed for the credit and/or the Btu conversion factor

    • Credit

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

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

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

    • Was the well drilled or re-completed during the appropriate window?

    • Was the well drilled into the same proation unit as another well?

    • Verify that the well was not completed into another geologic formation after receiving its final well determination from FERC. These determinations are specific to a completion, not a well.

    • Verify that gas from the well was being sold to an unrelated party.

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

Marginal Well Credit

  1. American Jobs Creation Act of 2004 Income Tax Provisions created new code section IRC 45I , Credit for Producing Oil and Gas from Marginal Wells. The provision creates a new $3 per barrel credit for qualified crude oil production and 50 cents per 1,000 cubic feet of qualified natural gas production. The term qualified production means domestic crude oil or natural gas produced from a qualified marginal well. In case of production from a qualified marginal well which is also eligible for the Nonconventional Fuel Source Credit allowed under IRC 45K, the taxpayer can claim the 45I credit only if it elects to not claim the IRC 45K credit. Refer to IRC 45I(d)(3).

  2. Qualified production must be treated as marginal production under IRC 613A(c)(6) or on an annual basis the well must have an average daily production of not more than 25 BOE and must produce water at a rate of not less than 95 percent of its total fluid output.

  3. This credit is available for production in taxable years beginning after December 31, 2004 and is a component of the general business credit subject to 5 year carry-back and 20 year carry-forward for any unused credits.

  4. This credit is not available to production when the reference price of crude oil exceeds $18 and the price of natural gas exceeds $2. The credit is reduced proportionately as the reference price ranges between $15 and $18 for crude oil and $1.67 and $2 for natural gas. Due to the current price of crude oil and natural gas, this section will not have an immediate effect on examinations.

Equipment Inventory

  1. The accounting for the individual owner-operator and the jointly owned oil and gas operating properties sometimes presents problems, especially regarding the accounting for the transfers of depreciable equipment between the lease equipment account and equipment inventory account.

  2. The individual who owns and operates his/her own oil and gas leases usually makes transfers from the producing lease equipment account to the inventory account at the fair market value of the used equipment at the time of the transfer. The COPAS Bulletins specify methods of valuation to be used. These methods generally provide for a value as a percent of new replacement cost based upon the condition of the used equipment. This value is normally used because the historical cost of the individual item of equipment is difficult to identify. If there is a large piece of equipment transferred and the original cost can be identified, it would be transferred at cost. The equipment inventory account is debited with this value or cost, and the lease equipment account is credited with the same amount. The depreciation reserve account is normally not disturbed, except for the depreciation on the equipment that is transferred at cost. Generally, no depreciation is claimed on the inventory account. This inventory equipment is on standby to be placed back into active service when it is needed. This method of accounting for the equipment transfers is normally not disturbed if the taxpayer uses this method consistently, and its use does not materially distort income. If the taxpayer makes sales of the equipment, then the gain or loss on the sale should be recognized at that time. The original cost less depreciation will be used in computing gain. Transfers from the inventory account to the lease equipment account are made at the same value. If there are purchases of equipment from outsiders and charged to the inventory account, those transfers out are usually made at cost, since the cost can be identified.

  3. The accounting for the equipment transfers on a jointly owned lease where the joint owner-operator does not take ownership of the equipment inventory account is similar to that of the individual owner. The transfers to the inventory account from the lease equipment account are usually made at cost, if cost is available, or at the fair market value of the equipment at the time of the transfer. The joint operating agreement between the joint owners and the lease operator will normally specify the method of transferring assets—see operating agreement in COPAS Bulletins. See below for the discussion of values placed on equipment by the operating agreement. The ownership of the inventory account is important because there has not been a disposition of the equipment if the joint owners retain ownership of the inventory account. It should be remembered that the taxpayers method of accounting for the equipment transfers will not be disturbed if the use of the method is consistent and its use does not materially distort income.

  4. The accounting for the equipment transfers on jointly owned leases where the operator is an outside third party presents fewer problems. Since a change in the ownership of the equipment takes place every time there is a transfer, gains and losses must be computed on each transfer. See IRM 4.41.1.3.8.1 for a full discussion of this problem and its relation to the operating agreement.

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

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

Oil and Gas Well Depletion

  1. An oil and/or gas producing property is a "wasting" asset. The quantity of oil and/or gas found in any natural deposit is finite. As the oil and/or gas is produced and removed from the deposit, the deposit is lessened or depleted. The owner of an economic interest in an oil and/or gas producing property may be entitled to a deduction from income for depletion of such economic interest as the oil and/or gas is produced and sold. Mineral interests, royalties, working interests, overriding royalties, net profits interests, and production payments are all economic interests in mineral deposits.

  2. Once a mineral property becomes productive, the owner or owners of economic interests in that property must recover their cost basis through the depletion deduction (or in the event of sale or other disposition prior to total depletion of the property as provided in the IRC for such sale or other disposition).

  3. IRC 611(a) provides, in the case of oil and gas wells, for a reasonable allowance for depletion as an allowable deduction in computing taxable income.

  4. The IRC provides two specific methods of computing the depletion deduction:

    • Cost depletion

    • Percentage depletion

  5. The cost depletion method is essentially a "unit of production" method of computing the allowable current tax period deduction. This computation is based on the taxpayer's basis as provided in IRC 612.

  6. The percentage depletion deduction is a specified percentage of the taxpayer's gross income from the property, but is limited to a maximum of 100 percent of the taxpayer's net taxable income from the property. This is generally termed the "100 percent of net income limitation" . The 100 percent of net taxable income is computed without allowance for depletion in IRC 613(a). Refer to IRM 4.41.1.3.9.1.4 for a full discussion.

  7. IRC 613A severely restricts the availability of percentage depletion for oil and gas production. In general, taxpayers classified as Independent Producers or Royalty Owners may claim percentage depletion on a limited volume of oil and gas production each year.

  8. If the percentage depletion is computed pursuant to IRC 613A(c), there is also a further limitation of 65 percent of the taxpayer's taxable income from all sources for the tax period in IRC 613A(d)(1). The method of computing the depletion deduction is not elective. The taxpayer must be allowed the deduction computation which allows the largest deduction. Allowable depletion, which is the higher of cost or percentage depletion, reduces the taxpayer's depletable basis (but not below zero) in the property.

  9. As this can involve a highly complex computation, an agent encountering a depletion problem should consult an engineer for assistance.

  10. The depletion computation is "off" book and the calculation of percentage depletion is solely for tax purposes. Corporate taxpayers should make a Schedule M-1 adjustment for excess percentage depletion over cost.

Purpose and Statutory Authority for Depletion
  1. The purpose of the cost depletion computation and deduction is to allow the taxpayer a tax-free return on capital investment. The purpose of the percentage depletion deduction is to avoid the problems which were connected with the "discovery value" depletion deduction and provide incentives to investors and operators to undertake the very risky drilling and exploration operations necessary to find and produce oil and gas. "Discovery value" depletion will not be allowed. Refer to IRM 4.41.1.3.9.1 for a full discussion.

  2. Cost depletion deductions are authorized by IRC 611, IRC 612 and the regulations issued pursuant to these sections. Prior to January 1, 1975, percentage depletion was authorized by IRC 613 and the regulations issued pursuant to this section. Subsequent to January 1, 1975, percentage depletion authorized by IRC 613, for oil and hydrocarbon gas wells, is substantially limited by IRC 613A. Those limitations are discussed in IRM 4.41.1.3.9.3. IRC 613A provides that, except for certain conditions listed, percentage depletion is allowable under IRC 613.

Economic Interest
  1. An economic interest in an oil and gas property is possessed in every case where a taxpayer has acquired, by investment, any interest in minerals in place and secures, by any form of legal relationship, income from the extraction of the oil and/or gas for which the taxpayers seeks a return on capital investment. Refer to Treas. Reg. 1.611–1(b).

  2. In many foreign countries, a corporation cannot acquire legal title to any of the lands, or to any petroleum or other hydrocarbons contained therein or produced therefrom. Rev. Rul. 73-470, 1973-2 CB 88 illustrates the rights and obligations that would permit a corporation to have an economic interest for purposes of depletion and intangible drilling costs with respect to United States federal income taxes.

  3. Depletion deductions are allowable only to the owner of an economic interest in the mineral deposit. Although a production payment is by definition an economic interest, IRC 636 provides that the payee will not be treated as the owner of an economic interest.

  4. The agent must distinguish between an economic interest and an economic advantage. The contractual right to purchase oil or gas after it has been produced is an economic advantage. See Rev. Rul. 68–330, 1968–1 CB 291. Court cases turning on the "economic interest" concept are Tidewater Oil Co. v. United States, 339 F.2d 633 (Ct. Cl. 1964); 14 AFTR 2d 6043; 65–1 USTC Para. 901A; CBN Corp. v. United States, 364 F.2d 393 (Ct. Cl. 1966); 18 AFTR 2d 5143; 66–2 USTC 86,703; cert. denied, 386 U.S. 981; Southwest Exploration Co. v. Commissioner , 350 U.S. 380 (1956); 48 AFTR 683; 56–1 U.S. 54,691; and Estate of Donnell v. Commissioner, 48 TC 552 (1967) AFF'D 417 F.2d 106 (5th Cir. 1969).

  5. The agent should be able to determine the "economic interest" status of an asset by obtaining from the taxpayer's property acquisition files or from any other sources the documents, letter agreements, assignments, unitization agreements, and operating agreements. The division order is the legal abstract of mineral interest in a specific property and indicates each party's percentage of ownership. These documents should be studied carefully for the nature of the interest owned by the taxpayer.

  6. The agent should not be concerned about the economic interest status unless the taxpayer has claimed depletion deductions or IDC deductions. These are the only types of deductions which are affected.

  7. If the taxpayer claims cost depletion deductions, the agent should be primarily concerned with basis, reserves of oil and/or gas, current tax period production, and the computation of the deduction.

Definition of Depletable Income
  1. For income tax purposes for tax years ending prior to January 1,1975, the gross income from the property is the amount for which the taxpayer sold the oil or gas in the immediate vicinity of the well, and the total was subject to percentage depletion. However, IRC 613A eliminated percentage depletion for some taxpayers and limited the amount of production subject to percentage depletion for others.

  2. Thus, in some instances, the entire gross income from the property may not be subject to percentage depletion because of the limitations of IRC 613A.

  3. In computing percentage depletion, the gross income from the property must meet the provisions of IRC 613A(b), and IRC 613A(c). Refer to IRM 4.41.1.3.9.3, Percentage Depletion for full details.

Gross Income from the Property
  1. For oil and gas wells, the IRC does not define gross income from the property. However, Treas. Reg. 1.613–3(a) still provides, "In the case of oil and gas wells, gross income from the property, as used in IRC 613(c)(1), means the amount for which the taxpayer sells the oil or gas in the immediate vicinity of the well. If the oil or gas is not sold on the premises but is manufactured or converted into a refined product prior to sale, or is transported from the premises prior to sale, the gross income from the property shall be assumed to be equivalent to the representative market or field price of the oil or gas before conversion or transportation." For court determinations of representative market or field price, see the following:

    • Shamrock Oil and Gas v. Commissioner, 35 T.C. 979 (1961)

    • Hugoton Production Co. v. United States, 315 F.2d 868 (Ct. Cl. 1963); 11 AFTR 2d 1198; 63–1 USTC 88,025

    • Panhandle Eastern Pipe Line Co. v. United States, 408 F.2d 690 (Ct. Cl. 1969); 23 AFTR 2d 69-933; 69–1 USTC 84,214

    • Exxon Corp. v. United States, 88 F.2d 968 (Ct. Cl. Fed Cir); 96–2 USTC 50,324; 77 AFTR 2d 2521; (Cert. denied)

    • Exxon Corp. v. Commissioner , 102 T.C. 721 (1994)

    • Exxon Mobil Corporation v. U.S., CA-FC, 2001-1 USTC 50,348, aff’g in part, rev’g in part, 2000-1 USTC 50,116, 45 FedCl 581, 244 F3d 1341

  2. Of prime importance in determining gross income from the property is the principle that only 100 percent of the proceeds of actual sales of oil and gas production in the immediate vicinity of the well or representative market or field price are subject to depletion.

  3. The deduction for depletion is to be equitably apportioned between the lessor and lessee. See Treas. Reg. 1.611–1(b)(2). The U.S. Supreme Court held in Helvering v. Twin Bell Oil Syndicate, 293 U.S. 312 (1934); XIV–1 C.B. 253; 14 AFTR 712; 35–1 USTC 386 that this meant the gross income on which percentage depletion is computed.

  4. When oil or gas is sold in the immediate vicinity of the well to an unrelated purchaser, there are relatively few problems. Gross income from the property includes any production or severance taxes which are the liability of the seller. These taxes are usually withheld by the purchaser (pipeline company) and paid to the state. If the purchaser of the oil or gas charges the seller a fee for gathering, transporting, and/or compressing the oil or gas, or if the seller performs these services, these costs are a decrease in gross income from the property and not lease operating expenses. Refer to Rev. Rul. 75–6, 1975–1 CB 178, for compression cost treatment and Panhandle Eastern Pipe Line Co. v. United States, 408 F.2d 690 (Ct. Cl. 1969); 23 AFTR 2d 69–933; 69–1 USTC 84, 214 for transportation cost treatment. The agent should analyze lease operating expense and "other" expenses to determine if these types of costs have been properly treated when paid to the pipeline purchaser. Analysis of depreciation accounts will indicate if pipelines or compressors are in use by the taxpayer. Gross income from the property can be verified as to source and type of income by studying and tabulating pipeline run statements and division orders. The contract between the purchaser and producer for sale of the oil or gas may have provisions which clearly indicate the portions of the purchase price which exceeds the field price of oil or gas in the immediate vicinity of the well.

  5. The working interest owner's gross income from the property must not include income from production which is paid to royalty owners and the other owners of economic interests in the property. Refer to Mesa Petroleum Co. v. Commissioner, 58 T.C. 374 (1972), and Treas. Reg. 1.613–2(c)(5)(i).

  6. When produced gas is not sold in the immediate vicinity of the well but is transported by the producer to a gasoline plant and processed for the extraction of liquid hydrocarbons, gross income from the property is deemed to be equivalent to the representative market or field price. However, there are instances in which there is no determinable representative market or field price. These situations have given rise to several court cases:

    • Weinert v. Commissioner , 294 F.2d 750 (5th Cir. 1961); 8 AFTR 2d 5417; 61–2 USTC 81,606

    • Mountain Fuel Supply Co. v. United States, 449 F.2d 816 (10th Cir. 1971); 28 AFTR 2d 71–5833; 71–2 USTC 87,650; cert. denied, 405 U.S. 989

    • Shamrock Oil and Gas v. Commissioner, 346 F.2d 377 (5th Cir. 1965).

  7. In the above instances, it is necessary to make a determination of gross income from the property by studying the data. If the depletion claimed for gas production is significant, the agent should request the assistance of an engineer.

  8. The percentage depletion deduction is based on a percent of the gross income from the property, which means the amount for which the taxpayer sells the oil or gas in the immediate vicinity of the well ( see Treas. Reg. 1.613–3(a)). If the sales price of the oil or gas is determined after transportation, compression, conversion, manufacturing, or similar activities, which are not production activities, the increase in the sales price attributable to those activities must be excluded from the price. Refer to Rev. Rul. 75–6, 1975–1 CB 178.

  9. Because the taxpayer is entitled to compute depletion on the gross income from the property, if the sales have occurred after one of the activities listed in paragraph (8) above, then a method must be devised to determine price in the immediate vicinity of the well. It should be emphasized it is a price determination not a value determination. The proportionate profits method applied in case of mines (Treas. Reg. 1.613–3(d)) has not been accepted by the courts for oil and gas.

  10. If a taxpayer has claimed percentage depletion on the sale of gas and the depreciation schedule shows the taxpayer also owns and operates a gasoline plant, the agent should analyze the source of income—plant sales or lease sales. If plant sales are allocated back to the leases, the agent should request engineering assistance.

Net Taxable Income from the Property
  1. Percentage depletion is computed on a property-by-property basis. The agent should become familiar with the "property concept" before attempting to determine taxable income from the property. For definition of "the property," see IRC 614 and the regulations thereunder. Also, refer to IRM 4.41.1.3.9.3.2, Property Defined.

  2. Taxable income from the property is important because the percentage depletion deduction is generally limited to 100 percent of the taxable income from the property. Refer to IRC 613(a). Taxable income from the property is computed in accordance with Treas. Reg. 1.613-5. For tax years beginning after December 31, 1997, and before January 1, 2008, or beginning after December 31, 2008, and before January 1, 2012 the net income limitation is suspended for domestic oil and gas production from marginal properties. Refer to IRC 613A(c)(6)(D) and IRC 613A(c)(6)(H).

    Note:

    The suspension is not applicable for tax years beginning after December 31, 2007 and before January 1, 2009

    .

  3. Net taxable income from the property is gross income from the property as determined in IRM 4.41.1.3.9.1.4 reduced by the following:

    1. Operating Expenses—IRC 162. The agent should check invoices on the larger accounts to see that the expenditures are reported for the correct properties and in the correct reporting period.

    2. Losses—IRC 165

    3. Depreciation of Lease Equipment—IRC 167 and IRC 168. The depreciation claimed for tax deduction purposes should be deducted to reach taxable income. If depreciation is claimed for equipment which served more than one property, the deduction should be allocated among the properties on a reasonable basis.

    4. Overhead Attributable to the Property —The taxpayer who produces oil and gas will have deductible expenses such as officers' salaries, office utilities, building depreciation or rent, and general office expenses which are not attributable to any particular property. These expenses are termed indirect or overhead. Treas. Reg. 1.613–5(a) requires that these expenses be allocated between producing activities and other activities. They must be further allocated to the individual properties on a reasonable basis. Allocation based on gross income or direct expense is acceptable but the method used should be consistently followed. Generally, allocations of overhead among properties on the basis of direct expenses is preferred since overhead is likely to be associated with direct costs. If the taxpayer has not allocated overhead to lease operating costs, the agent should scan the depletion schedule. If no properties will be affected, or only a minimal adjustment appears likely, the agent should not pursue the overhead allocation. The agent need not make calculations to allocate to each property—only to the ones which will result in adjustment, but the agent must be able to show that the adjustment is appropriate.

    5. Intangible Drilling Costs—IDC should be deducted for purposes of the 100 percent limitation. Refer to Rev. Rul. 77–136, 1977–1 CB 167. The costs of a dry hole drilled on a lease, in an effort to penetrate and produce an already producing property, are expenses of that property. The agent may be able to determine the purpose of a well by asking the taxpayer for the AFE or its equivalent which authorized the drilling of the well. This may be in the well file or company financial records. Companies which publish annual reports may include comments concerning some specific wells. Applications to drill the well which are filed with the state agency having jurisdiction also probably will indicate the purpose. The IDC of wells drilled for the purpose of locating and producing another pay zone on a lease already producing are not costs of the existing property, unless the taxpayer does not elect separate property treatment. Refer to IRM 4.41.1.3.9.3.6, Separate Mineral Interest Election.

    6. Advalorem and other taxes (other than Federal income taxes) should also be allocated to the properties per IRC 164.

    7. Interest expense on money borrowed to purchase or develop the property was decided in St. Mary's Oil and Gas Co. v. Commissioner, 42 B.T.A. 270 (1940).

  4. For an example of the correct computation of "Gross Income from the Property" and "Net Taxable Income from the Property," see Rev. Rul. 79–73, CB 1979–1, 218 and Rev. Rul. 81–266, 1982–2 CB 139.

  5. On occasion, a taxpayer may overpay IDC in a tax year and be reimbursed in the following year. The taxpayer then shows the reimbursement in the "taxable income" computation as a negative IDC deduction. This has the effect of showing a higher than actual taxable income from the property. Negative IDC should be removed from the computation as its inclusion distorts the taxable income calculation. Scanning the IDC accounts should identify any negative entries.

  6. If a taxpayer owns a fraction of the working interest and operates the property for others, the taxpayer charges the others an "overhead" or operating fee. This charge is income from operating properties for others and not a reduction in operating costs. When a taxpayer operates properties for others, as well as for itself, the agent should study the taxpayer's accounting for the income to verify that it is not being used to increase net income from the property or to reduce allocable overhead expenses.

  7. Gain, under IRC 1245, is not an allowable increase in net income from the property in the case of oil and gas wells as it is in the case of mines. Refer to Treas. Reg. 1.613–5(b).

  8. A taxpayer may follow the practice of only showing the IDC costs of producing wells on a depletion computation schedule. Dry-hole costs or some producing well costs may be shown under "other deductions" dry-hole costs, or abandonment losses. The agent should obtain schedules and supporting documents for these accounts. Comparison of names on the various schedules may indicate a dry hole was drilled on a producing property and its cost not deducted to reach taxable income.

    Example:

    Taxpayer Smith's percentage depletion schedule for R. Licker Lease shows gross income of $200,000, net income of $80,000, with an allowable percentage depletion of $80,000. The schedule of dry-hole costs totaling $126,000 may include an R. Licker Well No. 7 at $38,500. Investigation may also reveal this well was drilled as an intended extension in the known deposit. The result is percentage depletion of $41,500 ($80,000–$38,500).

Produced and Sold
  1. A depletion deduction is not allowable when the oil or gas is produced. The deduction is allowable when the produced mineral product is both produced and sold and income is reportable. Refer to Rev. Rul. 76–533, 1976–2 CB 189 and Treas. Reg. 1.611–2(a)(2).

  2. Oil or gas which is not sold but is transported from the property is depletable at its representative market or field price when used or consumed by the producer. See Rev. Rul. 67–303, 1967–2 CB 221, and Rev. Rul. 68–665, 1968–2 CB 280.

  3. The agent can determine the existence of depletion claimed on oil or gas which has not been sold by comparing the claimed gross income from the property for depletion computation purposes against the pipeline run statements and/or the gross income for income reporting purposes.

  4. Gas balancing agreements can have an effect on the reporting of gross income for taxpayers involved in a joint venture that elects out of the provisions of Subchapter K of the code. Refer to IRM 4.41.1.3.9.1.5.

Representative Market or Field Price
  1. As indicated under gross income from the property in IRM 4.41.1.3.9.1.6, oil or gas not sold in the immediate vicinity of the well but transported, manufactured, or converted prior to sale is included in gross income from the property at the representative market or field price. The terms representative market or field price are not defined in the IRC or Regulations but have been defined by the six court cases cited in the IRM.

  2. The representative market or field price is a factual determination that may vary among producer-manufacturers.

  3. As defined by the court decisions, the representative market or field price is a weighted average price per MCF of gas. The weighted average takes into account all wellhead sales of gas, which is comparable to the gas of the producer-manufacturer in terms of quality, pressure, and location. The computation includes all wellhead sales during the tax period without regard to the date the sales agreement was contracted.

  4. The representative market or field price may be different for two producer-manufacturers within the same field for the same year.

  5. If, on review of the producer-manufacturer's schedules of gross income from the properties, it is found that certain amounts are periodically computed rather than entered from pipeline run statements, the agent may find that the taxpayer should be using the representative market or field price.

  6. The agent may find under expense of operation amounts paid for compression, transportation, or other nonproducing types of expenses which indicate oil or gas is not sold in the immediate vicinity of the well.

  7. Gas lease operating expenses are usually comparatively low. Large operating expenses for gas wells warrant close checking to discover the cause.

  8. If an agent encounters a representative market or a field price problem, an engineer should be consulted.

Cost Depletion
  1. The cost depletion deduction method assures the owner of an oil or gas producing property that the allowable tax deduction is at least equal to the investment in the depleting property and tracks as rapidly as the asset is consumed.

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

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

  4. If a taxpayer receives a lease bonus on wildcat acreage and claims cost depletion equal to 100 percent of cost, this has the effect of claiming the minerals are worthless as they supposedly will produce no future income. Worthlessness must be proven by an event, and no such event has occurred. Further, it is assumed that the lease itself has value or the lessee would not have paid the bonus. Therefore, cost depletion should not be allowed unless it is possible to make a reasonable estimate of future income and that estimated income is not zero. However, for a contrary decision, see Collums v. United States, 480 F. Supp. 864 AFTR 2d 80–751 (DC Wyo. 1979) with respect to which no action on decision has been issued. Refer to PLR 8532011 and IRM 4.41.1.3.9.4 for additional details on lease bonuses.

  5. For estimates of recoverable units, see IRM 4.41.1.3.9.2.2, Reserves of Oil and Gas.

  6. In large cases with numerous calculations, a taxpayer's calculations can be quickly verified through a Computer Audit Specialist.

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

Depletable Basis
  1. As provided in IRC 612, generally a taxpayer's basis for the cost depletion computation is the adjusted basis under IRC 1011.

  2. When a taxpayer purchases an interest in a property and there is only one asset, few cost problems arise.

  3. Frequently, a problem of basis for cost depletion arises when a taxpayer purchases more than one asset for a lump sum. When a taxpayer purchases a producing lease and related equipment for a lump sum, the allocation of cost between leasehold (depletable) and equipment (depreciable) is controlled by Treas. Reg. 1.611–1(d)(4), Treas. Reg. 1.167(a)–5, and Rev. Rul. 69–539, 1969–2 CB 141. The cost is allocated between leasehold and equipment based on relative fair market values. However, Treas. Reg. 1.1245–1(a)(5) provide that on the sale of IRC 1245 property and non-IRC 1245 property, if the buyer and seller are adverse as to the allocation, any arm's-length agreement between the buyer and seller will establish the allocation. In the absence of such an agreement, the allocation is made by considering the appropriate facts and circumstances.

  4. Allocation of purchase price may involve a potential whipsaw (aka correlative adjustments) situation. Refer to IRM 4.10.7.4.9http://irm.web.irs.gov/Part4/Chapter10/Section7/IRM4.10.7.asp#4.10.7.4.9. When a material amount of tax is involved, secure the returns of both sides to the transaction to ensure consistency in the treatment of the transaction.

  5. Allocation of a lump-sum purchase price between leasehold and equipment is usually an engineering problem. The agent should secure the following before requesting engineering services:

    • copies of the contracts and purchase agreements

    • taxpayer's allocation method

    • workpapers for making the allocation

    • copy of the taxpayer's engineering report which was used as a guide in purchasing the assets

  6. Allowable depletion deductions reduce the taxpayer's remaining basis for cost depletion computations. Accounts should be maintained so that all capitalized cost and all allowable depletion is accumulated. If costs exceed the depletion reserve (accumulated depletion), the difference is the "remaining basis." The effect of this is that an addition to capital of any asset may be fully offset by previously allowed percentage depletion so that, immediately after a substantial capitalization, the taxpayer's "remaining basis" may be zero. See Rev. Rul. Rev. Rul. 75–451, 1975–2 CB 330, and Treas. Reg. 1.614–6(a)(3), Example 1.

  7. Costs which should be capitalized include:

    • purchase price or bonus

    • attorney fees

    • abstract fees

    • commissions or other fees paid in connection with acquisition of the property

    • IDC

    • equipment costs paid in excess of the percentage applicable to the interest owned by the taxpayer; refer to Treas. Reg. 1.612–4(a)(3).

  8. Other costs that may affect basis are:

    • IDC which the taxpayer has not elected to expense under IRC 263(c)

    • delay rentals

    • equipment costs which are required to be capitalized under Rev. Rul. 69–332, 1969–1 CB 87

    • favorable geological and geophysical costs for properties outside the U.S.; refer to Rev. Rul. 77-188, 1977-1 CB 76 and Rev. Rul. 83-105, 1983-2 CB 51, and IRM 4.41.1.2.2.3.2.

Reserves of Oil and Gas
  1. "Reserves" as of any date means the number of units currently and expected to be recovered subsequent to that date.

  2. In the computation of cost depletion, the "unit" " to be used is the principal unit or units paid for in the products sold. See Treas. Reg. 1.611–2(a). The unit for oil is barrels and for natural gas it is thousands of cubic feet (MCF). The IRS has traditionally allowed taxpayers to use the unit of the predominate product produced from each property or the "barrels of oil equivalent" which can be obtained by converting MCF’s of gas to equivalent barrels by dividing by a conversion factor of approximately 6 MCF per barrel.

  3. The estimates of reserves of oil or gas must be made "according to the method current in the industry and in light of the most accurate and reliable information obtainable" . Refer to Treas. Reg. 1.611–2(c)(1). The estimate (quantity)includes "developed" or "assured" and "probable and prospective" deposits. Industry definitions of proved reserves (proved developed and proved undeveloped) refer to minerals that are reasonably known, or on good evidence believed to exist when the estimates are made according to the method current in the industry and in the light of the most accurate and reliable information obtainable. All proved categories correspond to reserves described in Treas. Reg 1.611-2(c)(1) and should be included in the recoverable units for computation of cost depletion deduction. The examiner should closely review the taxpayer's reserves estimation, in light of operations or development work prior to the close of the taxable year, and include additional reserves required by applicable regulation to be consistent with industry standards and supported by taxpayer's actual practices. See IRS Coordinated Issue Paper, Cost Depletion Recoverable Reserves http://www.irs.gov/Businesses/Coordinated-Issue-Papers---LB&I.

  4. Effective for tax years ending on or after March 8, 2004 taxpayers may elect to use a "safe harbor" to calculate their total recoverable units. Total recoverable units are generally set equal to 105 percent of proved reserves (both developed and undeveloped) as defined by the 17 CFR of Regulation S-X (refer to IRC IRC 210.4-10(a) of Regulation S-X. The safe harbor must be used for all domestic oil and gas properties owned by the taxpayer. See Rev. Proc. 2004-19 and the Field Directive on Cost Depletion – Determination of Recoverable Reserves http://www.irs.gov/Businesses/Field-Directive-on-Cost-Depletion---Determination-of-Recoverable-Reserves.

  5. The "reserves" to be used in the cost depletion computations for any tax period are the "reserves" at the end of that tax period plus the units produced during that tax period. See Treas. Reg. 1.611–2(a)(3). This determination is important because the formula to compute cost depletion is generally the same as the one used to compute "depreciation, depletion, and amortization" (DD&A) for financial accounting. However, the amounts inserted into the various portions of the calculation are different. Care should be taken to assure that adjusting entries are being made to book amounts before tax cost depletion is calculated.

    CD= CP x [ATB/(CP+FP)]
    Where:
    ATB = Amount of depletable tax basis remaining
    CD = Cost Depletion
    CP = Current Production
    FP = Future Production as of end of year

  6. IRC 611(a) provides for situations in which revision of estimates impacts the calculation of depletion allowance. For purposes of cost depletion, the taxpayer is not permitted to revise the reserve estimate based solely on economic factors, without operations or development work indicating the physical existence of materially different quantity of reserves than originally estimated to purchase or to develop the property. See Martin Marietta Corp. v. United States, 7 Cl. Ct. 586, 85–1 USTC 9284 (Cl. Ct. 1985) and http://www.irs.gov/Businesses/Coordinated-Issue-Petroleum-Industry-Cost-Depletion---Recoverable-Reserves-(Effective-Date:--January-13,-1997).

  7. The units to be used in the calculation of cost depletion deduction of any taxpayer are only the units which have been and will be produced to the interest owned by that taxpayer.

    Example:

    Taxpayer A owns a royalty of 1/8 of production in Lease Z. Lease Z has produced 8,000 barrels of oil during the current tax period. At the end of the tax period Lease Z contains 80,000 barrels of oil reserves. Taxpayer A's units produced during the current tax period are 1/8 of 8,000 barrels or 1,000 barrels. Taxpayer A's reserves of oil for cost depletion computation are 11,000 which is 1/8 of 80,000 barrels plus 1,000 barrels.

  8. Making estimates of the reserves of oil or gas is an engineering project. In most cases when cost depletion deductions are significant, the taxpayer will have "in-house" engineers or outside consultants prepare the estimates of reserves for use by the accounting department. These estimates may be used for full cost accounting financial statements and/or tax computations. It is important to understand that the circumstances under which a reserves estimate may be changed for tax purposes are different from circumstances under which reserves can be changed for financial reporting purposes. The agent should obtain copies of these estimates and forward them to the engineer. Engineers should refer to IRM 4.41.1.3.9.2.3, Appropriate Additional Reserves of Oil and Gas.

  9. If a taxpayer's cost depletion approaches or exceeds 50 percent of the net taxable income from the property or the cost per barrel of oil produced appears excessive, the agent should investigate the facts concerning the acquisition of the property and the basis in the property. There may be errors in the allocation of cost, estimation of reserves, or basis claimed. Units claimed to be produced for depletion purposes may be in excess of those reported for income reporting purposes. Sometimes assets transferred between subsidiaries may have been transferred at "book" rather than tax basis. Assets transferred between subsidiaries may have been transferred at tax cost, but the related reserve accounts may not have been transferred. IDC which were expensed for tax purposes may have been capitalized for "book" and cost depletion purposes. In years that percentage depletion exceeded cost depletion the excess percentage depletion may not have been deducted from cost basis.

Appropriate Additional Reserves of Oil and Gas
  1. Disputes with taxpayers often arise in determining the quantity of "probable" or "prospective" reserves to be included in a property’s total recoverable units from oil and gas wells for purposes of computing cost depletion under IRC 611.

  2. Under Treas. Reg. 1.611-2, if it is necessary to estimate or determine with respect to any mineral deposit as of any specific date the total recoverable units of mineral products reasonably known, or on good evidence believed, to have existed in place as of that date, the estimate or determination must be made according to the method current in the industry and in the light of the most accurate and reliable information obtainable. The estimate of the recoverable units of the mineral products in the deposit for the purposes of valuation and depletion should include as to both quantity and grade:

    • The ores and minerals "in sight" , "blocked out" , "developed" , or" assured " , in the usual or conventional meaning of these terms with respect to the type of the deposits, and

    • "Probable" or "prospective" ores or minerals (in the corresponding sense), that is, ores or minerals that are believed to exist on the basis of good evidence although not actually known to occur on the basis of existing development. Such "probable" or "prospective" ores or minerals may be estimated: as to quantity, only in case they are extensions of known deposits or are new bodies or masses whose existence is indicated by geological surveys or other evidence to a high degree of probability; and as to grade, only in accordance with the best indications available as to richness.

  3. The minerals primarily produced in the petroleum industry are liquid and gaseous hydrocarbons. These are commonly referred to as oil, gas, and natural gas liquids. Some byproducts such as carbon dioxide and sulfur are also produced. Recoverable units or reserves volumes for hydrocarbons are usually reported as barrels (BBL) for liquids and thousands of cubic feet (MCF) for gases by domestic companies. Reserves may also be recorded in terms of barrel of oil equivalents (BOE) where the gas has been converted to an equivalent liquid volume (based on Btu content) and added to the oil reserves. International companies may use other units of measure for reserves in foreign locations. Examiners/engineers need to be aware that there are variations in reserve volume nomenclature, that standard conditions of volume measurement vary somewhat, and that conversion of gas volume to oil volume may be a source of error in determining hydrocarbon reserves.

  4. IRS examiners/engineers must follow the Coordinated Issue Paperhttp://www.irs.gov/Businesses/Coordinated-Issue-Petroleum-Industry-Cost-Depletion---Recoverable-Reserves-(Effective-Date:--January-13,-1997). According to the Coordinated Issue Paper, the taxpayer must include all proved reserves (both developed and undeveloped) in the cost depletion calculation. In addition, the taxpayer must include "appropriate additional reserves" which are generally referred to as probable reserves. The Coordinated Issue Paper also restates long-standing IRS policy that reserves estimates may not be revised solely because of changes in economic conditions.

  5. To minimize disputes over probable reserves, the IRS promulgated a safe harbor that taxpayers can elect for tax years ending on or after March 8, 2004. Refer to Rev. Proc. 2004-19, 2004-1 CB 563 and IRM 4.41.1.3.9.2.2.

Problems in Determining Recoverable Reserves
  1. Determining the correct quantity of recoverable units for cost depletion can be a challenging task. Examiners will likely find each taxpayer to have unique business records and practices related to the estimation and compilation of oil and gas reserves. In addition taxpayers may use terms that have a specific meaning to them, but different meanings to others. Examples include:

    • Reserves, recoverable units, expected ultimate recovery

    • Probable, prospective, possible, potential

    • Non-producing, undeveloped, noncommercial, static

    • Likelihood, reasonable certainty, confidence, probability

  2. Taxpayers estimate, compile, utilize, and report reserves in different ways for different purposes. Taxpayers may have reserve estimates for internal purposes different from those reported to the IRS. Taxpayers may consider "static reserves" to be reserves that are proved in the technical sense, but not commercially recoverable due to economic or political reasons.

  3. For the same occurrence (or anticipated occurrence) of oil and gas, taxpayers may determine different quantities associated with different categories. For example, the quantity of "unrisked" probable reserves may be higher than the "most likely" probable reserves.

  4. Taxpayers may estimate proved reserves down to the property level, but unproved reserves only down to the field level. Taxpayers may also have estimates of unproved reserves that are not in a ledger format, but instead are contained in analyses of specific property acquisitions.

  5. Examiners are likely to find that no "appropriate additional reserves" have been incorporated by the taxpayer in its cost depletion computation.

  6. Publicly traded oil companies must annually submit an estimate of their proved reserves (both developed and undeveloped) to the Securities and Exchange Commission (SEC) http://www.sec.gov/. Many taxpayers use these same reserves for cost depletion. However, some taxpayers exclude subcategories such as proved undeveloped reserves or proved non-producing reserves. SEC reserves can be very susceptible to negative changes in economic conditions, and may be less than the true proved reserves for particular properties. The SEC's reserves definitions and reporting guidelines for oil and gas activities are contained in Reg. section 210.4-10 of Regulation S-X of the Securities Exchange Act of 1934. http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&sid=20c66c74f60c4bb8392bcf9ad6fccea3&rgn=div5&view=text&node=17:2.0.1.1.8&idno=17#17:2.0.1.1.8.0.21.42

  7. The SEC’s definitions of reserves and reporting guidelines were essentially unchanged from 1978 to 2009. A major effort to modernize those items occurred in the late 2000s, and submissions to the SEC after December 31, 2009 must comport with the revised SEC regulation. The older definition of proved reserves is not available online, therefore it has been memorialized in Exhibit 4.41.1-45. For convenience a portion of the current SEC reserves definitions is provided in Exhibit 4.41.1-46. The major differences are summarized as follows:

    • Definition of "current prices" (for determining if the reserves are economic) is now based on 12-month historical average instead of the last day of the year. Industry considered the latter to be unreliable because it was suspect to aberrations in the daily price of oil and natural gas.

    • Nontraditional resources (such as "oil sands" and "oil shale" that are mined) are now considered oil and gas activities.

    • The "certainty level" needed to classify reserves can be based on modern technologies, instead of only certain specified technologies.

    • For estimates of proved undeveloped reserves, the certainty criterion has been replaced by "reasonable certainty" .

    • Companies have the option to disclose probable and possible reserves, and definitions of those terms are provided.

  8. The Service’s engineers have concluded that the impact of the SEC’s revisions on the cost depletion issue from a risk analysis standpoint is minor. For example, at present very few public companies have chosen to disclose probable and possible reserves. Further, even though "current prices" are now assumed equal to the prior 12-month average instead of the last day of the reporting year, some companies have announced write-downs of reserves due to declining natural gas prices in the U.S.

  9. Companies are also required by law to annually report to the Energy Information Administration (EIA) an estimate of proved reserves in the U.S. http://www.eia.gov/survey/form/eia_23s/instructions.pdf. Examiners should be aware of the peculiarities of this data -

    • Each company reports reserves for only those properties that it operates

    • The reserves are reported by field, not by specific lease or property

    • The reserves are reported on an 8/8 basis; therefore they are not net to the company's ownership interest.

    The EIA treats this information as proprietary, so examiners would have to obtain this information from the taxpayer. The EIA's definition of proved reserves is very similar to that of the Society of Petroleum Engineers (SPE). http://www.eia.doe.gov/pub/oil_gas/natural_gas/survey_forms/eia23li.PDF

  10. The Society of Petroleum Engineers (SPE) is the preeminent industry organization for defining petroleum resources and reserves. For many years the SPE has worked with industry participants and other associations to promulgate both reserves definitions and other guidelines for the use of reserves preparers or reserves auditors. Its most recent efforts resulted in the publication of the Petroleum Resources Management System (PRMS) in 2007. To a large degree the current SEC’s definitions generally agree with the SPE’s definitions. The SPE Oil and Gas Reserves Committee recently issued Guidelines for Application of the Petroleum Resources Management System (PRMS) http://www.spe.org/industry/reserves.php, November 2011. This document replaces the 2001 guidelines and expands content to focus on using the 2007 PRMS to classify petroleum reserves and resources.

  11. To promote consistency of examinations, examiners and engineers should become familiar with the items mentioned above which are available at http://www.spe.org/industry/reserves.php.

  12. The SPE definitions and classifications have been drafted in great detail. The key concepts can be seen by the following excerpts:

    • Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.

    • Proved Reserves. An incremental category of estimated recoverable volumes associated with a defined degree of uncertainty. Proved Reserves are those quantities of petroleum which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. Often referred to as 1P, also as "Proven" .

    • Probable Reserves. An incremental category of estimated recoverable volumes associated with a defined degree of uncertainty. Probable Reserves are those additional Reserves that are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50 percent probability that the actual quantities recovered will equal or exceed the 2P estimate.

    • Possible Reserves. An incremental category of estimated recoverable volumes associated with a defined degree of uncertainty. Possible Reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10 percent probability that the actual quantities recovered will equal or exceed the 3P estimate.

    • Uncertainty in resource estimates is best communicated by reporting a range of potential results. However, if it is required to report a single representative result, the "best estimate" is considered the most realistic assessment of recoverable quantities. It is generally considered to represent the sum of Proved and Probable estimates (2P) when using the deterministic scenario or the probabilistic assessment methods. It should be noted that under the deterministic incremental (risk-based) approach, discrete estimates are made for each category, and they should not be aggregated without due consideration of their associated risk. See SPE 2001 Supplemental Guidelines, Chapter 2.5.

  13. The Society of Petroleum Evaluation Engineers (SPEE) is also a good source of information on estimating oil and gas reserves at www.spee.org.

  14. IRS petroleum engineers have concluded that as a factual matter:

    • The SPE's definition of proved reserves refers to minerals described in Treas. Reg. 1.611-2(c)(1) in that they are "reasonably known, or on good evidence believed to exist." SPE proved reserves (both developed and undeveloped) should be included in the cost depletion calculation.

    • The SPE's definition of probable reserves is generally consistent with minerals described in Treas. Reg. 1.611-2(c)(1)(ii). They are reasonably analogous to "probable and prospective" ores or minerals. SPE probable reserves should be included at the appropriate time in the cost depletion calculation as discussed further in the Analysis of SPE Factual Scenarios of Probable Reserves that follows.

    • The SPE's definition of possible reserves is generally not consistent with minerals described in Treas. Reg. 1.611-2(c)(1). Their low level of confidence is not consistent with minerals that are "reasonably known, or on good evidence believed to exist" or those that are "probable and prospective" . Generally, SPE possible reserves should not be included in the cost depletion calculation.

Analysis of SPE Factual Scenarios of Probable Reserves
  1. The SPE's website for reserves definitions formerly included a description of several factual scenarios for probable reserves. IRS petroleum engineers analyzed each factual scenario and determined -

    • Whether the described scenario meets the criteria of Treas. Reg. 1.611-2(c)(1);

    • What quantity of probable reserves should be included in the cost depletion calculation; and

    • When the probable reserves should be included in the cost depletion calculation

    Even though the SPE no longer includes these factual scenarios in its discussion of reserves, they are universal in nature and provide a good reference point for examiners/engineers. In this analysis, the terms reserves, proved reserves, and probable reserves carry the same meaning as the SPE's former definition of these terms. Examiners/engineers should be cognizant that any particular taxpayer's definition of these terms may differ from the SPE's. The complete analysis is contained in Exhibit 4.41.1-26.

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.

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.

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.

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).

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.

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.

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.

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.

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.

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).

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.

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.

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

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.

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.

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.

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.

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).

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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).

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.

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.

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.

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).

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).

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).

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.

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.

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.

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.

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.

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.

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).

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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).

Exclusion from Subchapter K
  1. The typical oil and gas joint venture between working interest owners is technically a partnership for federal tax purposes. Refer to IRC 761 for definition of "partnerships" .

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

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

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

    • IRC 108 (regarding income from discharge of indebtedness);

    • IRC 617 (regarding deduction and recapture of certain mining expenses); and

    • IRC 901 (regarding taxes of foreign countries and U.S. possessions).

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

  6. Certain elections are important and should be made at the partnership level, including the following expenditures:

    1. Intangible drilling and development costs—to deduct or capitalize. Refer to IRC 263(c).

    2. Property unit—to treat as one property or separate properties. Refer to IRC 614.

    3. Subchapter K—election to not be treated as a partnership. See Treas. Reg. 1.761–2.

Sharing Income and Deductions
  1. With partnerships, it is important to remember that a partner's share of income and deductions will be determined from the partnership agreement. Enterprising oil and gas promoters use IRC 704 to allocate current deductions to investors who furnish money for drilling wells.

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

  3. Where an allocation does not affect the partner's capital upon liquidation, it will not usually be considered to have substantial economic effect. In such a situation, if the allocation is determined to lack substantial economic effect, the item will be reallocated in accordance with the partners’ interest in the partnership. Generally, this means the item will be shared among the partners on a per capita basis. An easily understood discussion on partnership allocations can be found in Cunningham and Cunningham, The Logic of Subchapter K, A Conceptual Guide to the Taxation of Partnerships, 2d (West Group, 2000).

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

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

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

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

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

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

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

Special Item Allocations
  1. Special partnership allocations such as losses and depreciation are equally valid in oil and gas partnerships.

  2. Common practice in oil and gas partnerships is for currently deductible costs to be allocated to certain partners. For instance, intangible drilling costs, well completion costs, and operating costs may be allocated entirely to limited partners. Special allocations are permitted under IRC 704, but they must have substantial economic effect. A review of IRC 704(b) and Treas. Reg. section 1.704-1(b) will provide guidance in this area. In addition, http://www.irs.gov/Businesses/Partnerships/Partnership---Audit-Techniques-Guide-(ATG) provides understandable examples.

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

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

    Example:

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

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

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

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

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

  3. 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.

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

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

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

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

    1. IRC 83

    2. Treas. Reg. 1.61–1 (a) and 1.721–1(b)

    3. Diamond v. Commissioner , 56 T.C. 530 (1971); aff'd, 492 F.2d 286 (7th Cir. 1974); 33 A.F.T.R. 2d 852; 74–1 USTC 9306

    4. United States v. Frazell , 335 F.2d 487 (5th Cir. 1964); 14 AFTR 2d 5378; 64–2 USTC 9684; cert. denied, 380 U.S. 961 (1965)

    5. Campbell v. Commissioner , TC memo 1990–162 (1990), aff’d in part and rev’d in part, 943 F.2d 815 (8th Cir. 1991).

    6. Rev. Proc. 93-27, 1993-2 CB 343, clarified by Rev. Proc. 2001-43, 2001-2 C.B. 191.

  4. It is not uncommon where a partner contributes property to a partnership that it has a tax basis different from its fair market value. If so, IRC 704(c) requires that a partnership must use a reasonable method to allocate deductions attributable to the contributed property to the non-contributing partners (to the extent possible) based on its book value. Furthermore, if the contributed property is sold by the partnership, the pre-contribution gain or loss must be allocated to the contributed partner.

Disguised Sales
  1. "Disguised Sales" are transactions in which taxpayers may attempt to use partnership structures to avoid sale treatment (i.e. realization of gain) on the exchange or other disposition of their highly appreciated oil and gas properties. These properties typically have high "built-in" gain due to the current deductions of IDC and/or accelerated depreciation of installed equipment. As a result, disguised sale transactions can pose material issues for examination.

  2. The basic fact pattern and tax treatment of a disguised sale is described as one where a partner directly or indirectly contributes money or other property to a partnership and there is a related direct or indirect distribution of money or other property by the partnership to the partner (or another partner). The contribution and distribution can occur in any order. Taking into consideration all facts and circumstances and viewing the transactions together, if such contribution and distribution are more properly characterized as a sale, then both transactions are treated as a taxable sale. Refer to IRC 707(a)(2)(B).

  3. For more detailed information, refer to Pub 541, Partnerships http://www.irs.gov/publications/p541/ar02.html and the Partnership Audit Technique Guide http://www.irs.gov/Businesses/Partnerships/Partnership---Audit-Techniques-Guide-(ATG).

  4. Disguised Sales pose complex, factually intensive, and time-consuming issue examination. A partnership technical specialist, subject matter expert and local Counsel can help.

  5. Suggested audit techniques include:

    1. Schedule M-2 for large distributions with corresponding reductions to specific assets on Schedule L

    2. Prior, current, and subsequent year Form K-1s, searching for large contributions and distributions

    3. Schedule M-3 for book-to-tax differences for the transaction in question

    4. SEC filings such as Forms 10-Q, 10-K and 8-K. Company and industry press releases reveal transactions not otherwise disclosed in financial statements. Also, determine how the transaction was treated for both financial and tax purposes.

    5. Structured disguised sale transactions often span multiple tax years. For example in early years, a taxpayer may reorganize its assets or entities in order to group oil and gas properties that it intends to include in a future transaction. Similarly, a taxpayer could enter into a financial arrangement, such as a production payment or loan, with the other party to the disguised sale several years before the other steps of the transaction occur.

    6. Copies of the contribution agreement, original and amended partnership agreements, any line of credit and/or other loan agreement, any indemnity agreement (or other similar side agreements between partners) as well as a written explanation of the business purpose of these documents. Also, consider requesting any internal financial and tax structuring document and any outside legal or tax advice.

Publicly Traded Partnerships

  1. Publicly traded partnerships (PTP) are fairly common in the oil and gas industry especially for midstream companies. IRC 7704 allows qualifying publicly traded partnerships to be taxed as a corporation. A partnership whose interests are traded on established securities exchanges or readily tradeable on secondary markets are considered to be publicly traded partnerships.

    Exception:

    IRC 7704(c) allows the PTP to maintain its classification as a partnership if 90 percent or more of its gross income is derived from qualifying passive-type income. In general, a taxpayer must continue to meet the gross income requirements on an annual basis to qualify for the exception. Examiners should consider verifying that a taxpayer's income qualifies and that it exceeds 90 percent of gross income.

  2. IRC 7704(d) refers to several types of qualifying income. Qualifying income related to the oil and gas industry includes income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including geothermal energy and timber). Examiners need to inquire if the taxpayer has previously requested a Private Letter Ruling on whether their income qualifies under IRC 7704(d).

  3. IRC 469(k) requires that losses from passive activities of a PTP can only be applied to income or gain from passive activities of the same PTP. Likewise, credits from passive activities of a PTP can only be applied against the tax on the net passive income from the same PTP.

Corporations

  1. The corporate form of organization is often used by investors in oil and gas exploration, particularly if an unusual amount of risk is involved, notwithstanding some unfavorable tax features.

  2. During the exploration and drilling stage, the adoption of Subchapter S status will enable the stockholders to deduct the losses from operations due to drilling costs being incurred because S corporations are flow-through entities. However, once the properties become profitable, the S corporation shareholder will pay tax on its pro rata share of the corporation's income. In addition, the shareholder of an S corporation having accumulated earnings and profits (generally from a former C-corporation) will pay tax on dividends distributed out of accumulated earnings and profits. Refer to IRC 1368. The percentage depletion deduction does not decrease earnings and profits and has the effect of increasing the taxability of dividends. Earnings and profits are only reduced by cost depletion. Treas. Reg. 1.316–2(e) provides, in part, "the amount by which a corporation's percentage depletion allowance for any year exceeds depletion sustained on cost or other basis, that is, determined without regard to discovery or percentage depletion allowances for the year of distribution or prior years, constitutes a part of the corporation's earnings and profits accumulated after February 28, 1913, within the meaning of IRC 316, and, upon distribution to shareholders, is taxable to them as a dividend." This rule is applicable to certain Subchapter S corporations as well as regular corporations. Distributions from corporations, including S-corporations with accumulated earning and profits, that are considered to be nontaxable should be considered as to the source of distribution. The corporation may be paying a dividend out of a percentage depletion reserve, which will be taxable.

Alternative Minimum Tax Considerations
  1. Oil and gas companies often have minimal regular taxable income and therefore the determination of Alternative Minimum Tax (AMT) liability is a very important consideration. The tax preference amount for IDC can significantly affect Alternative Minimum Taxable Income (AMTI). Since other deductions, such as accelerated depreciation, also give rise to a tax preference, examiners should perform a risk analysis prior to proceeding with the examination of any or all tax preference items.

  2. When the taxpayer is an independent producer (i.e., the taxpayer is not an integrated oil company) examiners should be aware that IRC 57(a)(2)(E) provides a general exception to the tax preference for IDC. However, that exception is limited and should be reviewed for correctness. Refer to IRM 4.41.1.5.4.1.2, Exception for Independent Producers and Its Limitation.

  3. Another aspect of AMTI to consider is LIFO inventory. Refer to IRM 4.41.1.6.1.5.

  4. AMT income and AMT are recorded on Form 4626, Alternative Minimum Tax - Corporations and Form 6251, Alternative Minimum Tax - Individuals. The below focuses on the computation by corporations.

AMT Computation of IDC Tax Preference Amount
  1. IRC 57(a)(2) states that IDC deducted with respect to oil, gas, and geothermal properties is a tax preference to the extent "excess" IDC exceeds 65 percent of the net income from the properties. The preference amount for all geothermal deposits is computed separately from the preference amount for all oil and gas properties that are not geothermal deposits.

  2. Not all IDC expenditures are taken into account in computing excess IDC. IDC incurred during the year in which the corporation elected to amortize over 60 months pursuant to IRC 59(e) is not taken into account. Similarly, IDC incurred with respect to wells drilled outside the U.S. is not taken into account since that IDC must be capitalized. Lastly, IDC incurred with respect to a nonproductive well (sometimes referred to as a "dry hole" ) is not taken into account. Whether a newly drilled well is nonproductive can be an examination item. Examiners should obtain a list of expenditures for IDC that were classified as nonproductive and then review IRM 4.41.1.2.4.4, Distinction Between IDC and Nonproductive Well Costs.

  3. Excess IDC is determined annually. Computation steps follow:

    1. First, determine how much IDC was paid or incurred during the taxable year in connection with oil, gas, and geothermal wells (other than costs incurred in drilling a nonproductive well) and was deducted under IRC 263(c) or IRC 291(b) for integrated oil companies.

    2. Subtract the amount which would have been allowed as a deduction in the taxable year if such costs had been capitalized and straight line recovery of intangibles had been used with respect to such costs. Refer to IRC 57(b)

    3. Under IRC 57(b) the taxpayer can choose for each well to compute "straight line recovery" by one of two methods, either straight line amortization over 120 months or by a permitted cost depletion method.

      Note:

      Straight line recovery begins with the month when production from the well commences, and is not tied to when IDC was incurred. Refer to IRC 59(e) and IRC 291(b). This could be very significant for high-cost wells that are drilled near the end of the year, especially if the taxpayer made a simplifying assumption that all its IDC was incurred exactly at mid-year and computed six months of amortization.

    4. The following example is based on a Joint Committee on Taxation staff report, General Explanation of the Tax Reform Act of 1986, p. 442.

      Example:

      Assume an integrated oil company incurred $1,000,000 of IDC in January 2011. It currently deducts 70 percent of that total ($700,000) under IRC 263(c). IRC 291(b) requires that $300,000 must be amortized over 60 months, yielding a deduction of $60,000 in 2011. The sum of those two amounts ($760,000) is compared to how much of the $1,000,000 IDC would have been allowed in 2011 under straight line recovery. Assume that amount is $50,000 because production started in July (6 months divided by 120 months and multiplied by $1,000,000). For 2011 the amount of excess IDC is $710,000 ($760,000 minus $50,000). The remaining IDC to be deducted under 291(b) in subsequent years is disregarded for computing excess IDC in those years ($300,000−$60,000=$240,000).

  4. To determine the IDC preference amount , excess IDC must then be compared to 65 percent of "net income from oil, gas, and geothermal properties" . Net income is the gross income the corporation received or accrued from all oil, gas, and geothermal wells minus the deductions allocable to these properties. When calculating net income, only income and deductions allowed for the AMT are considered. The IDC deduction is reduced by the amount of excess IDC. Only deductions incurred with respect to properties that generated gross income during the taxable year are included. Refer to Technical Advice Memorandum 8002016 (PLR 8002016). However, Rev. Rul. 84-128, 1984-2 CB 15 clarifies that properties which have wells that are capable of production, but which are shut-in, are included in the calculation. Presumably the computation is done at the consolidated return level and includes both domestic and foreign properties. However, there is no authority to include activities that occurred within a controlled foreign corporation.

  5. The following is an extension of the previous example in 4.41.1.5.4.1.1(4) and is intended to show how the tax preference amount is determined.

    Example:

    Assume the facts of the example above. Further assume the company has gross income from oil and gas properties of $850,000. For simplicity there are no expenses or deductions to consider other than IDC. To determine the AMT net income of the properties, the taxpayer's regular IDC deduction of $760,000 must be reduced by the excess IDC of $710,000, yielding a $50,000 deduction. Therefore AMT net income of the properties is $800,000 ($850,000 gross income minus $50,000 AMT expenditures). Sixty-five percent of the AMT net income of the properties is $520,000 ($800,000 × 65 percent). Finally, the IDC tax preference amount for the company is $190,000 ($710,000 − $520,000).

Exception for Independent Producers and AMT Limitation
  1. The tax preference amount for IDCs from oil and gas wells generally does not apply to corporations that are independent producers (as distinct from integrated oil companies as defined in IRC 291(b)(4)). However, the benefit of this exception may be limited. The amount by which the preference amount can be reduced cannot exceed 40 percent of AMTI when AMTI is computed as if the exception did not apply. Refer to IRC 57(a)(2)(E). This rule is illustrated with two examples.

    Example:

    Assume regular taxable income of an independent producer is $80 and the IDC tax preference amount is $20 (determined as if exception did not apply). For simplicity there are no other AMT preference amounts or adjustments to consider. Therefore "tentative" AMTI equals $100 ($80 plus $20). Forty percent of this tentative AMTI is $40. Therefore the entire IDC tax preference can be eliminated because a $20 reduction in the preference amount does not cause a reduction in AMTI that exceeds $40. AMTI is $80 ($80 regular taxable income plus $0 IDC tax preference amount).

    Example:

    Assume regular taxable income of an independent producer is $40 and the IDC tax preference amount is $60 (determined as if exception did not apply). For simplicity there are no other AMT preference amounts or adjustments to consider. Therefore tentative AMTI equals $100 ($40 plus $60). Forty percent of this tentative AMTI is $40 ($100 × 40 percent). If the exception were to apply in full, AMTI would be reduced by $60 ($100 − $40) so the benefit of the exception is limited to $40. The IDC preference is $20 ($60 − $40) and AMTI equals $60 ($40 regular taxable income plus $20 IDC tax preference amount).

  2. Chief Counsel Advice Memorandum 201235010 explains that when AMTI for an independent producer is negative, the IDC preference exception in IRC 57(a)(2)(E) does not apply. In other words, the IDC tax preference amount should not be reduced at all. Examiners have determined that some independent producers improperly reduced their IDC preference amount, and consequently their AMTI, when their AMTI was negative. The purpose was to increase AMT net operating loss.

Foreign Tax Credits and Subpart F
  1. IRC 907 provides a limitation on the amount of foreign taxes available as a credit under IRC 901 that were paid or accrued on foreign oil and gas extraction income (FOGEI) and foreign oil related income (FORI). Prior to 2009 tax years, these limitations were computed separately from each other and the limitations for taxes on other foreign income. Effective for 2009 tax years and beyond, the Energy Improvement and Extension Act of 2008 amended IRC 907 to extend the IRC 907(a) foreign tax credit limitation for taxes attributable to FOGEI to taxes attributable to FORI. The combination of FOGEI and FORI is termed "combined foreign oil and gas income" per IRC 907(b).

  2. For computing the separate adjusted AMT of a consolidated return member entity, annual reconciliation of FOGEI and FORI carryovers is necessary. See Prop. Treas, Reg. 1.1502-55(h)(6)(iv)(B).

  3. This provision of the law can be quite complex and consideration should be given to consulting with an international foreign tax credit subject matter expert or an international examiner when combined foreign oil and gas income generates foreign oil and gas taxes. when FOGEI or FORI generates foreign tax credits.

  4. IRC 954(g), Foreign Base Company Oil Related Income, is one type of Subpart F income that could be an issue. A referral of the case to an International Examiner should be considered. Refer to IRM 4.60.6.1 for referral criteria and procedures.

IRC 482 Intercompany Services
  1. Many companies in the oil and gas industry have scientists, engineers, mathematicians and other highly educated and experienced employees working in the United States in part for the benefit of controlled foreign corporations. Income from these intercompany services should be reported on the associated U.S. tax returns. Issues arise when taxpayers and examiners disagree on the amount of such income and the methodology to determine it.

  2. Some taxpayers argue that requiring these intercompany services to be reported on a basis other than cost violates the arm’s length standard of Treas. Reg. 1.482-1. Most oil and gas projects are conducted as joint ventures with one party designated to be the operator. Most companies are involved in numerous ventures, acting as operator in some and solely as joint venture members ("JVM" ) in others. Historically, the operators have agreed not to add any profit element to their internal charges to the JVMs for exploration, development and/or production activities (there are a few minor exceptions to this policy). Taxpayers claim that these JVMs are unrelated parties, acting at arm’s length, and, since they do not add a profit element onto similar services rendered to the joint venture, there is no need to add a profit element to similar on services rendered to the JVMs by related entities.

  3. However, examiners have generally determined that intercompany service transactions between the U.S. company and its Controlled Foreign Corporations (CFCs), and the service transactions between the JOA operators and its JVMs, are not comparable and do not satisfy the comparability provisions of Treas. Reg. 1.482-1(d)(1). The relationship between the operators and JVMs is unique and distinguishable from the relationship between U.S. companies and their CFCs. Indeed, a U.S. company has no participating interest in the CFCs' projects, and is generally compensated solely by service fees. In transactions with the JVMs, however, the JOA operator has a more expansive role than just providing services: it is developing an oil and gas project together with its JVMs, and is sharing that project's profits with the JVMs via the production from hydrocarbon extraction. The provision of services by the JOA operator to the JVMs is, in the overall picture, merely an ancillary transaction to the main endeavor, which is to develop the hydrocarbon asset in a manner that maximizes the profit for the operator and the JVMs. Thus, since the operator and the JVMs are co-venturers that jointly benefit from the profits of the project’s development and the services-at-cost agreement, it is not the most reliable measure of an arm’s length transaction for services provided by a U.S. company to its CFCs. This is only one example to distinguish the relationships and transactions between the US company and its CFCs, and those between JOA operators and the JVMs. Many more may exist depending on the specific facts and circumstances. If this issue or a similar issue is identified during an oil and gas examination, examiners should consider involving a Section 482 international subject matter expert, an international examiner, and Local Counsel.

IRC 199 Domestic Production Deduction
  1. IRC 199 provides a Domestic Production Deduction (DPD) for tax years beginning in 2005. It is a deduction allowed for U.S. taxpayers who have domestic production activities. The DPD is a percentage of the lesser of the taxpayer's taxable income or qualified production activities income (QPAI) for the taxable year, subject to wage limitations.

DPD Issues Specific to the Oil and Gas Industry
  1. Expanded Affiliated Group. For a taxpayer that is a member of an Expanded Affiliated Group (EAG), all members are treated as a single corporation and the deduction is allocated among them based on each member's QPAI, regardless of whether the member has taxable income or loss or W-2 wages for the taxable year. Within an EAG, the activities of its members are attributed to each other. For example, where an integrated EAG extracts natural gas or crude oil, processes or refines that natural gas or crude oil, and sells the resulting items, the EAG is treated as a single corporation whose DPGR are attributable to both extraction and manufacturing. However, when a member of an EAG participates in a joint venture or partnership, the separate pass-through rules generally apply to that member’s activities. Refer to Treas. Reg. 1.199-5 for application of IRC 199 to pass-through entities. Since joint ventures are common in the oil and gas industry, this could be an area of non-compliance.

  2. Qualifying vs. Non-qualifying for Purposes of DPD. Generally, the gross receipts generated for the following types of oil and gas activities in the United States qualify as Domestic Production Gross Receipts (DPGR):

    • Exploration and production companies engaged in the extraction and production of oil and gas. Gross receipts must be attributable to their working interest in leaseholds and should include only their portion of gross revenues.

    • Refining and/or petrochemical companies engaged in the refining of oil or manufacturing of petrochemicals.

    • Manufacturing companies engaged in the manufacturing of tangible personal property such as oil field equipment but only if they properly have the "benefits and burdens" of the manufacturing process per Treas. Reg. 1.199-3(f)(1).

    • Construction companies engaged in the construction of US real property. Construction activity means an activity under the two-digit NAICS code of 23 and any other NAICS code that relates to the construction of real property such as NAICS code 213111 (drilling oil and gas wells) and NAICS code 213112 (support activities for oil and gas operations). Treas. Reg. 1.199-3(m)(4) provides that oil and gas platforms are explicitly included in the definition of infrastructure, which is a qualifying type of real property. Thus, the construction of oil and gas platforms in the U.S. qualify as construction activity DPGR.

  3. Generally, the gross receipts generated for the following types of activities are NOT eligible for inclusion in DPGR:

    1. Gross receipts derived from non-operating mineral interests. For example, royalty income is a non-operating interest income and therefore not includible in DPGR. Treas. Reg. 1.199-3(i)(9).

    2. Gross receipts relating to the sale of products that the taxpayer did not manufacture or refine. For example, gross receipts relating to gasoline sales at a convenience store are not qualifying except in the case where a taxpayer is selling their own refined products. Integrated taxpayers may extract natural gas or crude oil, process or refine that natural gas or crude oil, and sell the resulting items in their own convenience store. Taxpayers may also have purchased crude oil or refined products for resale that they did not extract, manufacture, or refine themselves. These products could be purchased for a variety of reasons, for example to satisfy a long-term supply contract. Examiners may find the gross receipts from these products accounted for as a part of refinery operations or in a marketing/distribution function. Regardless of the reason purchased or the operational area used, these purchased-for-resale products should not be included in DPGR.

    3. Gross receipts relating to transportation and distribution. For example, pipeline companies’ gross receipts generated in the transportation of products are generally not includible for purposes of DPGR. However, where an integrated oil company is transporting its own extracted product through its own pipeline to its own refinery, the transportation of such product could be includible in DPGR if all of such activities are included in the same EAG.

    4. Gross receipts attributable to the transmission of pipeline quality gas from a natural gas processing plant to a local distribution company's citygate (or to another customer) are non-DPGR.

    5. Gross receipts relating to convenience store revenues from non-gasoline sales (for example food and beverages) is not included in DPGR.

    6. Gross receipts related to methane gas extracted from a landfill. Refer to Treas. Reg. 1.199-3(l)(2).

    7. Gross receipts generated from the sale of a leasehold interest, regardless of producing or non-producing. For sale of producing leaseholds, Chief Counsel Advice (CCA) 201208029, released February 24, 2012 addressed the situation where an exploration and production company sold producing oil and gas properties and treated its entire capital gain as qualifying for IRC 199. The CCA concluded that gross receipts from the sale of Leasehold Rights are not DPGR under IRC 199(c)(4)(A)(ii). However, the gross receipts attributable to the sale of the Well (and well equipment) may qualify as DPGR. Also, if any capitalized IDC was included in the basis of the Lease, then such amounts should be considered costs related to the construction of the Well and an allocation of such may qualify for DPGR (but not more than the actual capitalized IDC included).

  4. Examiners should be aware of other types of income that are generally not related to the production of qualified property. For example, service income is not included in DPGR. Also, rental income is generally not included in DPGR unless the property rented was manufactured by the same taxpayer in accordance with other requirements of Section 199. If a company claims DPGR on rental of tangible property and it is not performing qualifying construction activities, such as drilling oil and gas wells, an examiner should consider contacting Local Counsel and the appropriate Section 199 subject matter expert.

  5. Allocated Expenses for Purposes of QPAI. The extraction and production of oil and gas have certain unique associated costs. Generally, taxpayers should include all costs associated with the extraction of the crude oil and natural gas or other qualifying activities that can be allocated and apportioned to a class of qualifying income per IRC 861 and the treasury regulations thereunder. For example, if a qualifying activity is from extraction, the following expenses are some examples of such directly allocable and includible costs:

    • Depletion (cost and percentage)

    • Depreciation

    • Geological and geophysical expenditures

    • Leasehold abandonments

    • Intangible Drilling Costs

    • Dry hole expenses

  6. Oil related Gross Receipts for QPAI. For tax years 2010 and beyond, the applicable DPD percentage is held at 6 percent for oil related QPAI, verses 9 percent for other activities.

    1. "Oil related" QPAI is income attributable to production, refining, processing, transportation, or distribution of oil, or any "primary product" thereof. Total QPAI should be calculated and then the reduction under IRC 199(d)(9) should be made to the extent there is oil-related QPAI. Refer to IRC 199(d)(9) . Oil related QPAI must first qualify under normal rules of QPAI to qualify for 6 percent. Therefore, gross receipts from transportation and distribution do not qualify even if they are oil related. However the exception for integrated oil companies as explained in 4.41.1.5.4.4.1 (3) c) still applies.

    2. IRC 199(d)(9) refers to IRC 927(a) for definitions of the primary products of oil and gas. The regulations under IRC 927(a) provide that petrochemicals, medicinal products, insecticides and alcohols are not considered "primary products" from oil or gas.

  7. Examination teams should consider analyzing the costs associated with petrochemicals vs. "Oil related" QPAI because of possible attempts to shift costs away from non-oil related QPAI (such as petrochemicals) to oil related QPAI to maximize the total DPD.

  8. Partnerships

    1. "Take-in-kind" and "elect-out" (of Subchapter K) partnerships are common in the oil industry. Instead of the partnership selling the oil and gas that it produces, it distributes the oil and gas to its partners for each to sell or use. Without the exception described below, neither the partnership nor the partners would have qualifying DPGR since the partnership did not have third party sales and the partners cannot be attributed the qualifying activities of the partnership. See Treas. Reg. 1.199-5 for general IRC 199 rules for partnerships.

    2. A "qualifying in-kind partnership" is defined in Treas. Reg. 1.199-3(i)(7)(ii) and includes only certain partnerships operating solely in a designated industry – oil and gas, petrochemical, electricity generation, extraction and processing of minerals. The regulations provide that for "qualifying in-kind partnerships" each partner is treated as performing qualifying activity, such as extracting the property (e.g. oil and gas) that is distributed by the partnership to that partner. See Treas. Reg. 1.199-9(i)(7) for how this is accomplished. It is important to note that the taxpayer must be a partner in the partnership at the time the partner disposes of the property.

  9. Qualified Exchanges . Energy companies sometimes exchange crude or refined oil products with other energy companies to achieve operational objectives. These arrangements are often made to save transportation costs by exchanging a quantity of product A in location X for a quantity of product A in location Y. The regulations provide a safe harbor that generally addresses the product exchanges above. The safe harbor is allowed for eligible property, which includes oil, natural gas, or petrochemicals, or products derived from oil, natural gas or petrochemicals, or any other property or product designated by notice in the Internal Revenue Bulletin. The safe harbor provides that "gross receipts derived by the taxpayer from the sale of eligible property received in an exchange, net of adjustments to account for difference in the eligible property, may be treated as the value of the eligible property received by the taxpayer in the exchange" . Thus, if energy companies C and D enter into a product exchange with a product that would have otherwise qualified as DPGR to both C and D, the fact that the product is ultimately sold to the consumer by the other respective energy company doesn’t disqualify the original products from DPGR treatment for both C and D. The safe harbor requires a period of time for the exchange to be a qualified exchange per Treas. Reg. 1.199-3(i)(1)(iv)(B).

Subchapter S Corporations—Elections

  1. IRC section 1362(a) provides that a small business corporation as defined in IRC 1361(b), may elect not to be taxed and thus pass on a pro rata portion of the corporation's income for which the shareholder is liable for any tax. An S-corporation has no earnings and profits, except for any attributable to a taxable year prior to 1983 or to a taxable year in which it was a C-corporation.

Dividends—Excess Depletion
  1. An S corporation that was a C corporation at one time may have accumulated earnings and profits. In general, the earnings and profits of an electing Subchapter S corporation are computed in the same manner as any other corporation. In the computation of earnings and profits of an S corporation, the earnings are reduced by the taxable income, because the shareholders are required to include in their gross income. The results of this computation and other adjustments required by IRC 1368 may cause distributions in excess of the undistributed taxable income to be treated as ordinary dividends in the hands of the shareholder.

  2. If corporate distributions made in the current year are in excess of current undistributed taxable income, the earnings and profits for the current and prior years should be verified to ensure proper excess depletion is being taken. The adjustments section on Schedule M–2 of Form 1120S should be inspected for such excess depletion adjustments.

Passive Income—Termination
  1. IRC 1375 imposes a corporate level tax on excess net passive income if an S corporation has C corporation accumulated earnings and profit. Excess net passive income is passive income in excess of 25 percent of the S corporation's gross receipts, reduced by allowable deductions. For these purposes, passive income is similar to portfolio income as defined under the passive activity rules, which includes the royalties from oil and gas production payments, royalties, and overriding royalties. This would not include those production payments which do not retain economic interest status and are characterized as loans. Also does not include mineral, oil and gas royalties if the income from those royalties would not be treated as personal holding company income under IRC sections 543(a)(3) and (4) if the taxpayer was a C corporation. Some oil and gas lease bonuses are also considered "passive investment income" . If an S corporation has more than three consecutive years of passive investment income in excess of 25 percent of its gross income, the S election is terminated as of first day of the fourth year. Refer to Treas. Reg. 1.1362-2(c)(5)(ii)(A).

  2. The examiner should be alert to the types of oil and gas income of electing Subchapter S corporations. The passive investment income relating to the oil and gas business when added to other types of passive investment income could result in an entity level tax or in a termination of the S corporation election.

Associations Taxable as Corporations

  1. The exploration, development, and operations of oil and gas properties are carried on in various business structures and forms, such as co-ownership, joint ventures, and partnerships. It is usually desirable to avoid the corporate form since the intangible drilling and development deductions would benefit only the corporation, and the percentage depletion in excess of cost depletion is added to taxable income in computing earnings and profits. It is normally more desirable to choose that organizational form which will enable the individual taxpayer to benefit the most from the tax deductions in their higher tax brackets. Normally, a partnership or disregarded entity will achieve this result.

  2. Prior to promulgation of the "Check-the-Box Regulations" , the tax classification of business entities followed a complex system of entity classification under what was known as the "Kintner Regulations" . These regulations required organizational forms that were not corporations in the legal sense to be classified as corporations for tax purposes if they possessed the following corporate characteristics:

    1. Associates

    2. An objective to carry on business and divide the gains therefrom

    3. Continuity of life

    4. Centralization of management

    5. Liability for corporate debts limited to corporate property

    6. Free transferability of interest

  3. Effective January 1, 1997, the Check-the-Box regulations replaced the Kintner regulations by simply allowing the taxpayer to check the appropriate box on IRS Form 8832. Treas. Reg. 301.7701–2(b)(1) and (3) through (8) list entities that are "per se" corporations that cannot change their classifications. Under Treas. Reg. 301.7701–3 entities not listed, such as limited liability companies (LLCs), are "eligible entities" that are treated as partnerships if they have two or more members. If the eligible entity has one member it will be disregarded for federal income tax purposes. An eligible entity can also elect to change its classification.

Limited Liability Companies

  1. The limited liability company (LLC) is a hybrid business structure that combines the benefits of a sole proprietorship or partnership with those of a corporation. Like a corporation, an LLC offers its owners a limited liability shield that protects the business owners' personal assets from the debts or liabilities of the business. Like a partnership (or sole proprietorship), the LLC may allow all business income and loss to flow through to its owners. For these reasons, the LLC is becoming an increasingly popular format for doing business in most industries, including the oil and gas industry.

Petroleum Refining

  1. This section provides instructions for dealing with the many facets of the refining process.

  2. Miscellaneous subjects and situations common to the oil and gas industry will be considered in this section. These topics were selected because they involve transactions or situations that are not common in other industries.

  3. Exhibits and useful examination aids have been included at the end of this section. This material was included to provide inexperienced agents with tools that can be used in the examination of oil and gas operations. The suggested examination procedures are not mandatory but recommended for consideration.

  4. Additionally more pertinent research material is shown in Exhibit 4.41.1-1 for study of the manufacturing phase of oil and gas operations.

Petroleum Refining Overview

  1. Refining (as well as petrochemical) operations are basically manufacturing operations and, as such, involve additional aspects beyond the production technology discussed elsewhere in this handbook.

  2. Refining operations may involve a relatively simple separation of components as in a topping plant or, as found in a modern large refinery, a separation of components plus the breaking down, restructuring, and recombining of hydrocarbon molecules.

  3. In past years, domestic topping plants or skimming plants were sometimes used (i.e., Farmer's Cooperatives) to distill off light components with the sale of possibly only gasoline or diesel fuel. The residue was then subsequently processed at a major refinery to produce a full range of products. Domestic simple topping plants are a rarity today. In some foreign operations, topping plants are used to segregate rough cuts of the local crude. These cuts and virgin crude oil are then blended to produce a blend of crude suitable for sale/transportation to a particular refinery/market area depending upon the design of the refinery and/or the desired mix of finished products.

  4. Modern large scale refineries not only produce the normal refinery products (kerosene, jet fuels, gasolines, heavy oils, etc.), but also are a source of feed stocks for the petrochemical industry.

  5. Refiners make substantial investments to meet EPA requirements pertaining to emissions from their operations and fuel quality standards. Beginning in 1989, EPA required gasoline to meet volatility standards (in two phases) to decrease evaporative emissions of gasoline in the summer months. Upon passage of the 1990 Clean Air Act amendments, EPA began monitoring the winter oxygenated fuels program implemented by the states to help control emissions of carbon monoxide. It also established the reformulated gasoline (RFG) program which is designed to reduce emissions of smog-forming and toxic pollutants. EPA also set requirements for gasoline to be treated with detergents and deposit control additives. More recently, EPA has set standards for low sulfur gasoline and low sulfur diesel which will help ensure the effectiveness of low emission-control technologies in vehicles and reduce harmful air pollution. See http://www.epa.gov/otaq/fuels/index.htm. The American Jobs Creation Action created Code Section 179B (House Bill Section 338) and Code Section 45H (House Bill Section 339) which provided tax incentives for small business refiners in complying with EPA sulfur regulations. Refer to Exhibit 4.41.1-27.

  6. Exhibit 4.41.1-12 provides an analysis of hydrocarbon series found in crude petroleum or in intermediate/finished product streams after refinery processing.

Refinery Processes
  1. Originally petroleum refining was a rather simple process of separating crude oil into its component parts by distillation. The fractional distillation of an average crude oil yields a relatively small gasoline fraction, with larger amounts of kerosene and gas oil. Exhibit 4.41.1-13 illustrates distillation fractions of a typical crude oil. While the temperature range for indicated fractions remains relatively constant, the percentage distilled will vary based on the specific type crude involved.

  2. Conversion of the higher-boiling materials into more valuable products (gasoline or petrochemical feedstocks) is essential. Conversion is partially accomplished in the cracking process by which the large paraffins are broken down to yield a mixture of smaller paraffins, olefins, etc. Such conversion enables the refiner to convert as much as 80 percent of some crude oils into gasoline (if desired) whereas, only about 20 percent could be attained by fractional distillation. In addition, the cracking and other processes not only increase the quantity of gasoline, but also the quality.

  3. While the cracking process conversion of the heavier hydrocarbons to gasoline range hydrocarbons increases the quantity of gasoline products, the process also reflects an overall volumetric gain or increased yield. The total products produced, as a percent of feed to the unit, will reflect a 15–25 percent gain in volume (115–125 percent yield) due to the changes in gravities after cracking or hydrocracking. If refinery measurements were by weight, the yield would be approximately 100 percent.

  4. The cracking process produces both saturated and unsaturated hydrocarbons. Other processes are used for recombining the resulting hydrocarbons to produce finished refinery products or for separating individual products as specialty feedstocks for the petrochemical industry. Separation of component streams is accomplished by additional fractionation, absorption, or solvent extraction. Precise separation/extraction of a particular product by fractionation is not always possible due to the small difference in boiling points. While some refineries may have a "super fractionation" area producing finely defined cuts, particular product extraction is often accomplished by absorption or solvent extraction.

  5. In addition to the cracking and recombining of the hydrocarbons, other processes are available for the rearrangement of straight-chain hydrocarbons into ring or cyclic structures, the conversion of straight-chain hydrocarbons to branched-chain hydrocarbons, the removal of hydrogen to produce highly reactive hydrocarbons with double or triple bonds and/or aromatics, and the production of complex branched molecules of the paraffinic series. Some of these processes involve shrinkage (due to changes in gravities) with volumetric yields of 75–90 percent. See Exhibit 4.41.1-12 for illustrations of the various hydrocarbon arrangements. The relationship or arrangement of the hydrogen and carbon can be altered in many ways, and the resulting products have distinct characteristics.

  6. Exhibit 4.41.1-14 provides a chart depicting the petroleum refining process. A specific refinery may or may not have all of the indicated processing units, or it may have additional units (isomerization, coking, asphalt, etc.). However, the chart is illustrative of possible product flows between some processing units.

  7. The engineering design of a refinery is based on the type(s) of crude to be processed and optimum production of products. Actual production of the amounts of specific products will fluctuate, within limited parameters, based on seasonal demands or economic market conditions (i.e., a refinery designed to produce up to 60 percent gasoline may at times produce a lesser amount of gasoline with increased fuel oil production to satisfy seasonal demands, etc.).

  8. Refinery operational flexibility is controlled by changes in individual processing unit operating conditions or by diversion of streams between units.

    1. Changes in operating conditions could involve an adjustment to the severity on the reformers to increase/decrease yields versus decreased/increased quality (octane number) or an increase in the temperature in the catalytic cracker to generate more olefins and ultimately more alkylate.

    2. Diversion of streams could involve sending the catalytic cracked light gas oils to be blended to furnace oil (for seasonal demands) rather than hydrocracking the total available stream, blending butylenes directly into gasoline instead of alkylating, or diverting the higher boiling components of straight-run naphtha (reformer feed) making more kerosene/turbine fuel.

    3. Operational flexibility may also involve the coordination of shutting down of a single unit for repairs (turnaround), based on seasonal production demands. While a hydrocracker improves the quantity and quality of both gasoline and distillate blending stocks, its most important advantage is its ability to swing refinery production from high gasoline yields to high distillate yields. With seasonal peak production of distillates, the hydrocracker may be shut down for repairs.

    4. The simplified flow diagram shows the entire hydrocrackate stream going to the catalytic reformer. In actual operations, fractionation of the hydrocrackate can produce a heavy hydrocrackate, a light hydrocrackate, and a kerosene range stream. These streams are suitable for distillate blending stocks or for upgrading to gasoline blending stocks.

  9. In addition to the above design and operational flexibility in producing normal refinery products, the feasibility of producing petrochemical feedstocks creates other variables. The light gases from a catalytic cracker contain hydrogen, ethylene, propylene, and butylene. Separation of these components provides a design/operational stream for either alkylation or petrochemical feedstock. Catalytic reforming is a source of aromatic hydrocarbons (benzene, toluene, and xylene). Solvent extraction of aromatics from the reformate can provide a valuable petrochemical feedstock.

Petrochemical Industry
  1. The importance/interaction of the petrochemical industry cannot be ignored when considering refining operations. The inter-relationship in research, licensing/royalty fees, disposition of intermediate products, and many other items must be analyzed through contractual arrangements, joint ownerships, and trade-offs, among others.

  2. The potential utilization of petroleum based (hydrocarbon) building blocks is tremendous. Available byproducts of cracking (ethylene and propylene) provide the principal building blocks of the petrochemical industry. Methane can be converted to ammonia and ammonia to nitric acid. Anhydrous ammonia can be commercially sold in the liquid form as a fertilizer, or the ammonia and nitric acid can be combined to provide a solid fertilizer of high nitrogen content. Another example involves the production of synthetic rubbers. Successive dehydrogenation of n-butane produces 1,3–butadiene (plus hydrogen to be used in other processes). Polymerization or copolymerization of this product provides Buna rubbers for many products including automobile tires.

Refining and Petrochemical Operations
  1. The integrated oil and gas operator may have its own petrochemical plants and/or may be involved in petrochemicals through arrangements with third-parties.

  2. Fully integrated oil and gas operators with in-house divisions/companies for production, shipping, refining, petrochemicals, marketing, research and development, etc., provide a challenge in determining proper accounting for cross division/company operations. Research and development operations provide benefits and services to the other divisions/companies as well as development of patents, etc., available for lease or sale to third-parties. Intermediate streams or product streams from one plant provide feedstock for another plant.

  3. Refining/petrochemical arrangements with third-parties may involve actual partnerships or be joint ventures with individual variable percentage ownership in the feed preparation plant(s) and the petrochemical plant(s) involved. In such integrated joint ventures, frequently an operating committee is responsible for daily operations, but has no ownership.

  4. Particular problems encountered in such joint operations are further discussed in IRM 4.41.1.6.8, Joint Operations.

Catalysts
  1. In refining/petrochemical plant processes, catalysts are frequently employed. By definition, a catalyst is a substance that hastens or retards a chemical reaction without undergoing a chemical change itself during the process. Such processes involve many substances as catalysts. Examples are acids, minerals, metals, mixed metals, metallic oxides or halides. Metallic catalysts may be utilized in the free state (i.e., gauze or sponge form) or bonded to a base material to facilitate handling or usage.

  2. While the catalyst does not undergo any chemical change in the process, it may become inactive or ineffective after a time, due to physical abuse or buildup of impurities. Some processes include ongoing provisions for regeneration (i.e., burning off of carbon buildup) of physically stable catalysts. Where precious metals are involved (platinum, gold, silver, rhenium, etc.), reclamation of any physically deteriorated catalyst is standard operating procedure. Such reclamation usually involves returning the material to the manufacturer for reprocessing with credit for the precious metal (normally, practically no operational or reclamation loss of the precious metal is experienced).

  3. The cost of catalysts is handled in different ways according to the types of catalyst involved and the taxpayer's accounting method(s). Some taxpayers may charge the catalyst to expense when it is placed in use. Others may capitalize the initial cost and claim depreciation. In some cases the catalyst may be rented or leased under a standard supply contract. The correct tax accounting method for handling catalysts depends on the contractual arrangements, the type of catalyst involved, and operational factors, among them operational life, recoverability, and reclamation. Refer to IRM 4.41.1.6.8.2 for further discussion of catalysts.

Inventory - LIFO
  1. Refiners have historically used the Last-In, First-Out (LIFO) method for inventory accounting that is covered in IRC 472 and the regulations thereunder. The "dollar value" method of pricing LIFO inventories is specifically covered in Treas. Reg. 1.472-8.

  2. It is beyond the scope of this manual to explain how LIFO inventory prices are calculated. However, examiners should be aware that some refiners have elected to use the Inventory Price Index Computation (IPIC) method that is addressed in Treas. Reg. 1.472-8(e)(3). IPIC relies primarily on consumer or producer price indices published by the U.S. Bureau of Labor Statistics (BLS). The election to use IPIC may constitute a change in method of accounting. See Treas. Reg. 1.472-8(e)(3) and Rev. Proc. 2011-14, IRB 2011-4 330.

  3. LIFO inventory adjustments can affect the Adjusted Current Earnings (ACE) component in the AMT income calculation. See IRC 56(g)(4)(D)(iii) and IRC 312(n)(4).

LIFO - Definition of Items
  1. Oil and gas taxpayers can be defining items in their calculation of LIFO inventory pools too broadly. Combining numerous types of crude oil or refined products into fewer items within pools for LIFO may not clearly reflect income.

  2. Example:

    It was determined that a Petroleum Refiner defined LIFO items too broadly in a 2008 Field Attorney Advice. Inhttp://www.irs.gov/pub/irs-lafa/080401f.pdf

    1. The Petroleum Refiner had 2 LIFO pools, one for crude oil and one for refined products.

    2. For the crude oil LIFO pool, the taxpayer maintained 3 items of inventory. However, the taxpayer’s books and records defined approximately 140 different stock-keeping units (SKUs) within the 3 items.

    3. For the refined products LIFO pool, the taxpayer maintained 12 items of inventory. However, these items were comprised of SKUs ranging from 4 to approximately 108 per item.

    4. Based on the facts and circumstances, it was concluded that the taxpayer’s definition of an item did not clearly reflect income because the overly broad definition could result in compensating the taxpayer for effects of artificial inflation resulting from changes in quality and/or product mix.

  3. Crude Oil and Other Feedstock Pools

    1. The physical characteristics of crude oil depend on varying scales of heavy versus light crude (measured by API specific gravity) and sweet versus sour crude (measured by sulfur content).

    2. The price of crude oil varies with specific gravity. Lighter gravity crude oils tend to be more expensive because they tend to yield higher portions of more valuable refined products. Another factor in price is sulfur concentration. Generally, lower sulfur concentration is more desirable since refineries vary to the extent they are equipped to remove it.

Accounting Practices
  1. There is no standard system of accounting employed by oil refineries, nor are there any prescribed examination guidelines within the industry.

  2. In some situations, the refinery may operate as a self-contained entity preparing its own tax return or, in the case of a multinational conglomerate, feed its operational results back to corporate headquarters for consolidation.

  3. Since refinery managers need various types of data to evaluate and control their operations, numerous types of reports and analysis are prepared using complex cost accounting techniques.

  4. The examining agent should obtain a complete working knowledge of the accounting system prior to beginning his examination and should be cautious not to devote time to internal allocations having no tax significance.

  5. An example of an information document request which could be used in a review of the accounting system is shown in Exhibit 4.41.1-15. This exhibit also provides a list of some terms which might be of use when reviewing the cost accounting system.

  6. A prime area of examination concern should be the proper treatment of various types of overhead/indirect expenses.

  7. Consideration should also be given to the form of business entity under which the refinery operates. Refer to IRM 4.41.1.6.8 for a discussion of Joint Operations.

Referral and Coordination

  1. During the course of an examination, the agent may discover items that are highly complex and unique which require the experience and expertise of a specialist examiner and/or a specialist within the Industry itself. A Technical Specialist with the Office of Pre-Filing and Technical Guidance (PFTG) — Petroleum is a good resource in such situations.

Foreign Crude Pricing
  1. A major element in the cost of production at a refinery, and a significant source of examination potential, is the use of foreign crude oil.

  2. Delegation Order 4-17 on Foreign Produced Crude Oil providing for servicewide coordination was rescinded effective 12/01/2011. Agents should refer to International Examination of IRC 482 transactions http://lmsb.irs.gov/hq/pftg/transferpricing/index.asp.

International Examiners (IE)
  1. In addition to the examination potential to be found in crude oil pricing, International assistance from an international examiner may be required if issues are present.

Computer Audit Specialists (CAS)
  1. The use of a CAS is discussed inhttp://irm.web.irs.gov/link.asp?link=4.41.1.1.3.2. It is essential that the CAS be requested as early in the examination as possible. Consultations should also be held during the course of the examination concerning updating existing record retention agreements in view of current experiences.

  2. Examples of possible applications which may be helpful are to be found in Exhibit 4.41.1-17.

Engineers
  1. In addition to the skills of a petroleum engineer, the assistance of a general/industrial engineer may be required in the event the refinery has been involved in a major expansion or repair program. Refer to IRM 4.41.1.6.3, IRM 4.41.1.6.6, and IRM 4.41.1.6.7 for discussion of potential examination areas.

Excise Taxes
  1. An excise tax examination may be conducted as a separate examination, as part of the "package audit" requirements for an Industry case. It is mandatory for the Coordinated Industry Case (CIC) Program.

  2. A review of the taxpayer's retained copies of Forms 720 (Quarterly Federal Excise Tax Return) in conjunction with a "transcript" of taxpayer's account (and in light of the examination of the taxpayer's income and deductions per books and the income tax returns under examination) may indicate that an excise tax examination is warranted. This decision should be made as early as possible in each case so the examination work can be coordinated to the maximum extent desirable.

  3. Review of the quarterly federal excise tax returns, Form 720 with attachments, is an important part of the examination of a taxpayer that owns or operates a refinery. The operator of the refinery may be liable for certain excise taxes.

  4. Refer to IRC 4081(a)(1) in which a tax is imposed on certain removals, entries and sales of gasoline, diesel fuel, and kerosene. These three fuels are collectively referred to as "taxable fuel" . See IRC 4041(a) for tax on liquids other than gasoline (usually diesel fuel and kerosene used or sold for use in a diesel-powered highway vehicle or diesel powered train). IRC 4041(a)(1)(B) provides an exemption if these fuels were previously taxed as taxable fuels. IRC 4041(a)(2) imposes a tax on alternative fuels (excluding gas oil, fuel oil, and taxable fuel) used or sold for use in a motor vehicle or motorboat. Alternative fuels include those fuels referred to a "special fuels" prior to 10/01/2006. Common alternative fuels are liquefied petroleum gas (such as propane, butane, pentane, or mixture of these fuels). IRC 4042 imposes a tax on any liquid used by any person as a fuel in commercial waterway transportation known as an Inland Waterway tax.

  5. The oil spill liability tax is an environmental tax. This $.05 per barrel tax generally applies to crude oil received at a U. S. refinery and to petroleum products entered into the U.S. for consumption, use, or warehousing. The tax also applies to certain uses and the exportation of domestic crude oil.

  6. The tax imposed on ozone-depleting chemicals (ODCs) is also an environmental tax. This tax is imposed on an ODC when it is first used or sold by its manufacturer or importer. The manufacturer or importer is liable for the tax. The instructions for Form 6627 (Environmental Taxes) lists the taxable ODCs and tax rates.

  7. Verification of the environmental taxes reported on the Form 6627 attached to the Form 720 (Excise Tax Return) may include the following items for Ozone-Depleting Chemicals or Imported Products (refer to IRC 4661 and IRC 4671:

    1. Identification of the source documents, chart of accounts, flowcharts, operations manual, and responsible parties involved;

    2. Records of all Ozone-Depleting Chemicals produced, and records of all Ozone-Depleting Products imported;

    3. Records of the sale, export, or use of Ozone-Depleting Chemicals or Products;

    4. Records to substantiate that the appropriate tax has been paid previously, including floor stocks, if applicable.

  8. The environmental taxes deduction ledger account(s) should be analyzed and traced to source documents for a representative period. The examiner should determine that the taxable chemicals were properly classified for the appropriate tax rate, and that none of the taxable chemicals and none of the petroleum liquids were omitted from the amounts reported on Form 6627.

Capital Expenditures

  1. A major area of interest in the examination of refineries and petrochemical plants is the cost basis of property. The cost basis of tangible expenditures and intangible assets is involved in the determination of amortization, depreciation, and gain or loss on the disposition of all or part of such property.

Allocation of Acquisition Costs
  1. In any transaction where different properties or assets are acquired, there is the problem of allocation of the basis to the various properties or assets. In some contracts, the amounts involved for each separate property or asset is stated. When stated at realistic values, the allocation problem may be eliminated. The acquisition of a refinery, refinery facilities, patents, processes, and know-how involve complex allocations of the purchase price.

  2. The costs incurred incidental to the acquisition of a capital asset should be capitalized to the cost of the asset. Expenditures to be capitalized include items such as commissions, consulting fees, feasibility studies, environmental impact studies, legal fees, salaries, travel, and "new image" costs incidental to the acquisition of assets or expansion of the business. These incidental costs may include expenditures involved in forming a joint venture or a partnership. See IRM 4.41.1.6.8, Joint Operations.

  3. Any costs incidental to the acquisition of a capital asset and having a benefit to the taxpayer beyond the current year should be capitalized, as part of the cost of the asset acquired or constructed. It is noted that the cost of such environmental studies should be distinguished from expenditures deductible under the provisions of IRC 174. Rev. Rul. 80–245, 1980-2 CB 72 and the potential problems involving environmental impact studies are discussed in IRM 4.41.1.6.3.4.

  4. Examiners should be aware that the MACRS recovery period for refineries and petrochemical plants is 10 and 5 years respectively. See Asset Classes 13.3 and 28.0 in Exhibit 4.41.1-43.

  5. Some taxpayers have asserted that certain assets located at their refineries should be depreciated using Asset Class 28.0. Guidance to examiners on this issue is provided by Field Directive on MACRS Asset Categories for Refinery Assets.

Examining Acquisition Costs
  1. When examining acquisition costs, verify the total purchase price (including the adjusted cost basis of any property given in exchange), the incidental costs of the acquisition, etc.

  2. Verify the allocation of the total acquisition cost to the respective assets acquired in ratio to their relative fair market values at the date of acquisition. Acquisition costs should be allocated to items such as:

    1. "Going concern," "new image," environmental impact studies

    2. Patents, licenses, processes, and know-how assets

    3. Equipment and plant facilities

    4. Pipeline and storage facilities

    5. Land, right-of-way, and land improvements

    6. Inventories (including pipeline "fill" ), intermediate stream and finished products, warehouse equipment and parts.

  3. Some of the documents that should be examined for verification of acquisition costs include:

    1. Authorization for expenditure (AFE) records

    2. Letters of intent, offer, and counteroffer documents

    3. Minutes of executive committee meetings and directors' meetings

    4. Settlement sheets, transaction closing documents, papers transferring the consideration and conveying title

    5. Purchase price/fair market value analysis and allocation workpapers used as the basis for recording the cost basis of the individual assets on the books

    6. Analysis of the history and the projected performance of the tangible and the intangible assets including evaluation reports, Insurance coverage, and an itemized list of assets before and after the acquisition

    7. Details for the vouchers of the original entries in the journals and ledger of accounts

    8. Chart of accounts before and after the acquisition

    9. Organizational chart before and after the acquisition

    10. General information available such as employee newsletters, reports to stockholders, reports to SEC, or news releases.

Construction Costs
  1. Construction costs, in general, fall into three categories: initial refinery construction, expansion of refining capacity, and other improvements. In each category construction costs may include outside contractors, self construction, or a combination of both.

  2. Contracts with outside contractors should be reviewed to ensure that all costs itemized in the contract have been properly considered as capital expense. The agent should also verify that the items included in the construction contract are properly classified or allocated for depreciation. Engineering assistance may be required where a lump sum construction contract calls for items to be constructed which will fall into more than one category for depreciation.

  3. The agent should verify that appropriate self-construction costs have been properly capitalized. A good examination technique, when reviewing outside contractor costs, is to inquire if the taxpayer was furnishing personnel or equipment to supervise or assist in the construction process.

  4. When self-construction costs are encountered, the agent should ensure that the capitalized costs include the direct costs, as well as the indirect costs such as insurance, benefits, and overhead.

Environmental Impact Studies
  1. In the oil and gas business, as with other industries, construction activities such as building pipelines, roads, canals, refineries, and industrial plants can have an adverse effect on the natural environment. Sometimes the company will spend a great deal of money making studies of the effect the proposed business expansion will have on the environment. Should these costs be deductible as ordinary operating expenses or should they be capital expenses? Any cost incidental to the acquisition of a capital asset and having a benefit to the taxpayer beyond the current year should be capitalized as part of the cost of the asset acquired or constructed. However, if the study results in the abandonment of the project, the cost would be deductible under IRC 165 in the taxable year the taxpayer decides to abandon the undertaking.

  2. In the examination of taxpayers that have had large expansions, or have constructed plants that might have an environmental impact, the agent should be alert for such costs that might not have been capitalized.

  3. Expenditures to conduct environmental impact studies to support its application to expand its facilities are not research and experimental expenditures, within the meaning of IRC 174. Whether such expenses are capital expenditures will depend upon the facts of the particular case. The expenses, if not chargeable to a capital account, are ordinary and necessary business expenses deductible under IRC 162(a) . Rev. Rul. 80–245, 1980–2 CB 72 holds that the costs of environmental impact studies paid by a public utility company in connection with its application to expand its generating facilities are not research and experimental expenditures within the meaning of IRC 174.

Patents, Processes, and Know-How
  1. The operation of refineries and petrochemical plants often involves the utilization of numerous patents, exclusive processes, and trade secrets. During the examination of these operations, the agent should be alert for acquisitions of these types of assets. These items are capital assets and may be amortized over their useful life.

  2. The purchase of these types of assets frequently will occur when other items of plant, property, or equipment are being purchased. When other items are purchased, the agent should inquire if the purchase includes any patents, exclusive processes or know-how.

  3. Know-how may be defined as an aggregation of data or information that is employed in a business endeavor and has the effect of providing the user with a competitive advantage over others who do not have access to, or use of, such data or information.

    1. Royalty payments for the purchase or license of know-how that are contingent upon the use of (and reasonable in terms of the benefits actually derived from) licensed know-how during the year for which the payment is made can be deducted as necessary and ordinary business expenses.

    2. All other expenditures for know-how, with a few rare exceptions, must be capitalized and are not subject to the allowance for depreciation or amortization.

Crude Oil Inventory

  1. The inventory of refiners may include both domestic and foreign crude. See IRM 4.41.1.6.4 and IRM 4.41.1.6.6.1. The domestic and foreign crude inventory may include both produced and purchased crude oil.

  2. In the examination of refinery and petrochemical operations, the agent should obtain the assistance of engineers if problems are encountered in the determination of the correct value of produced crude oil that is included in the inventory of a refiner.

  3. The acquisition of crude oil for manufacture into finished products by refiners will be either through long-term contracts of supply by domestic and foreign producers or by spot purchases of crude oil on an as needed basis. The agent should be alert to per unit (barrel) variances in purchase price of purchased crude, especially if acquired from related entities.

Blending Stocks
  1. Finished or saleable refinery products are a blend of various refinery streams and sometimes include purchased blending stocks. The prime example is gasoline.

    1. With reference to the Simplified Flow Diagram in Exhibit 4.41.1-14, finished gasoline would be variable blends of the straight-run gasoline, reformate, catalytic cracked gasoline, thermal cracked gasoline, alkylate, and n-butane. These individual product streams (stocks) are normally segregated in storage tanks prior to actual blending operations.

    2. For a refiner without the modern processing units to produce high quality gasoline components, or one faced with the temporary shutdown of such a unit, blending stocks are frequently purchased on the open market. Blending operations and blending stocks are further discussed in IRM 4.41.1.6.6.1.2.

  2. The refiner's unfinished products inventory will normally include all produced or purchased basic stocks available for further processing or blending into finished products. The unfinished products inventory may be subcategorized to include:

    • Liquefied Petroleum Gas (LPG) Stocks

    • Gasoline Stocks

    • Kerosene and Gas Oil Stocks

    • Residual Stocks

    • Lube and Wax Distillate (Unfinished)

    • Industrial Chemicals

    • Additives

    • Catalysts

Finished Products
  1. The refiner's finished products inventory will include all saleable products resulting from further processing and blending of unfinished stocks. Individual refineries produce different products and taxpayer's categorization and sub-categorization will vary. Refer to Exhibit 4.41.1-18 for a list of the types of goods found in product inventories.

Spare Parts and Equipment
  1. To avoid unplanned shutdowns and to assist in performing routine maintenance, refineries normally maintain an inventory of spare parts and equipment.

  2. The agent should examine those spare parts and equipment items that should be or are being inventoried. Items not held for resale are not inventory, and LIFO cannot be used to account for such items per Treas. Reg. 1.472–1. For non-inventory treatment of expendable, rotatable, or standby emergency spare parts, see Rev. Rul. 81–185, 1981–2 CB 59.

  3. With respect to equipment, the agent should determine that proper consideration is given to investment credit and recapture of investment credit for items being placed in service or removed from service.

"Line Fill" Inventory Issue
  1. As explained in more detail in IRM 4.41.1.6.1.1, refineries convert crude oil and intermediate feedstock into finished petroleum products by a variety of physical, thermal, and chemical separation processes. Products that have been partially refined within the refinery are commonly called intermediate products. These intermediate products also must be included in inventory. Refer to Treas. Reg. 1.471-1.

  2. Examination coined the term "line fill" to describe, in one name, intermediate product volumes within the refinery. However, line fill refers to all product volumes located within piping, processing units, surge tanks, vessels, drums, boilers, cylinders, reactors, vats, kettles, hoses, and other containers used within a refinery in the process of refining crude oil and intermediate feedstock into finished products and feedstock for sale. Line fill volumes are distinct and separate amounts from the tank volumes found in the taxpayer's storage tank farms, for both crude oil and finished products. The term "line fill" should also not be confused with the term "line pack" or "cushion gas" . Line pack refers to the volume of gas in a pipeline necessary to provide sufficient pressure to distribute gas over a large geographic area, and it is generally of uniform composition.

  3. Examiners have observed that some taxpayers incorrectly account for line fill by:

    • Not treating any line fill as inventory

    • Not treating the proper amount of line fill as inventory (i.e., physical line fill volumes at year-end exceeds the volumes recorded for tax)

    • Treating line fill costs as deductible or depreciable

  4. Some taxpayers may attempt to capitalize or depreciate the cost of line fill as part of the refining assets and depreciate it over the life of the refining equipment. Some taxpayers may not capture any line fill at all for tax accounting purposes, as either a separate capital asset or separate inventory item, and presumably expense the cost as incurred. Typical arguments from taxpayers are that line fill is necessary for the equipment to operate, or that depreciation is appropriate because of molecular changes to the petroleum product within the refinery.

  5. Line fill represents petroleum products that are in the process of being manufactured and therefore the changes that are brought about are intentional. Depreciation allowance applies only to that part subject to, among other things, decay or decline from natural causes (refer to Treas. Reg. 1.167(a)-2). The molecular changes in the crude oil and feedstocks are not brought about from natural causes, but from intentional manufacturing actions. In contrast, line fill is a direct, income-producing factor because taxpayers are in the process of manufacturing a substantially transformed product, which is being held for sale. Thus, line fill is analogous to work in process and must be included in inventory (refer to Treas. Reg. 1.471-1).

  6. Line fill represents a vast array of manufactured and work-in-process inventory items. Suggested steps by examiners include:

    1. Determine if line fill volumes are captured within the existing tax inventory amounts. The refinery's tank farm inventory and line fill inventory may be held in different reporting entities so the agent should reconcile the inventory amounts down to the tank-detail level and/or reporting entity.

    2. The total amount of line fill volume that actually exists within a refinery may not be properly captured in the taxpayer's inventory records. Examiners may need the assistance of a petroleum engineer to determine the types of petroleum hydrocarbons and the location and amounts of feedstocks within the refinery, as well as to identify the correct price for determining year-end inventory dollar amount.

    3. The examination team should consider reviewing the taxpayer's regulatory agency filings with respect to refinery volumes. Refer to Exhibit 4.41.1-42.

    4. If the examiner finds discrepancies in the taxpayer's dollar or volume amount of line fill inventory, an adjustment under IRC 481 may be required. Examiners are encouraged to contact an Inventory Subject Matter Expert or Local Counsel in the examination of line fill inventory issues.

Sales and Transfers

  1. Transactions involving disposition of raw materials, or the products of the refinery, may be reported as exchanges, transfers, or sales. Crude oil exchanges must be reported in crude oil costs using the basis of the item given up plus or minus any "boot" and related expenses of the particular exchange. Accordingly, it is necessary to distinguish an exchange agreement, a buy/sell agreement, and a true sale agreement.

  2. Exchange agreements may exist when:

    1. Both sides of the agreement are stated in a single document

    2. The two agreements are negotiated simultaneously

    3. The two agreements refer to each other

    4. One side of the transaction involves a financial disadvantage sufficient that a prudent businessman would not enter into that part without the financial benefit of the other part of the agreement or agreements

  3. Transfers of products intracompany may be recorded at cost basis and reported in the cost of sales of the respective divisions or recorded at "arm's-length" value and reported as a sale of products transaction. When refinery products are transferred to an intracompany division or to a related domestic company at cost, or at a stated value, the impact on the taxable income should be considered.

  4. Transfer of products to or from a foreign related company should be examined. The product pricing should be evaluated against the "arm's-length" value so as to ensure that taxable income is not distorted and to ensure that the foreign tax credit is correctly determined. Refer to International Program Audit Guidelines (IRM 4.61) for discussion of international issues.

  5. Buy/sell agreements are accounted for as "normal" purchase/sale transactions. They may involve transporting, handling, or warehousing petrochemical products. These agreements should be examined to verify what was done. Special consideration should be given to transactions near the end of the year when such agreements may be made to cover a LIFO inventory layer without physical delivery of the product. The examiner should be alert for identical "contra" agreements after the end of the year to offset the prior agreement. LIFO inventory issues are discussed in IRM 4.41.1.6.1.5.

  6. True sale agreements and buy/sell agreements involve dispositions which are not exchanges or transfers reported in the cost of sales such as crude oil or other product transactions. The area of interest for the examination of the sales accounts, in addition to the gross receipts reconciliation, includes the special agreements with related parties (both domestic and foreign entities) and joint venture arrangements. Potential issues may involve "arm's-length" pricing, timing, and/or the character of the sales reported. Joint operations are discussed in IRM 4.41.1.6.8.

Refinery Products
  1. The refining/petrochemical products are ready for marketing at various points of the manufacturing process, including distillation, cracking, and treating. The various "split off" points in the manufacturing process are noted, in general terms, in the discussion in IRM 4.41.1.6.1.1 Refinery Processes.

  2. Finished refinery products such as fuel and lubricating oil are the principal products sold. The accounting for amounts reported in gross sales of these products should be reconciled to the sales journal or ledger. Potential issues include transfers, exchanges, or sales at less than "arm's-length" value. The main line of petroleum finished products are illustrated in Exhibit 4.41.1-18.

  3. Unfinished products in the manufacturing process are sometimes saleable for various uses, such as raw material for further refinery processing, blending, or as feedstock for many different manufacturing processes. The best known market for these "intermediate stream products" is their use in the manufacture of fertilizers, synthetic rubber, and plastics.

  4. The petrochemical manufacturing plant may be nearby or contiguous to the refinery to take advantage of the convenient source of raw material. The plant may be an intracompany or related company-owned facility. The list of divisions and/or related companies and their business operations should be ascertained from the annual report to stockholders or SEC reports http://www.sec.gov/. The areas of interest for examination include "arm's-length" pricing and "timing" of the transactions reported on the return.

  5. As technology progresses, substantially all of the by-products from the refining process are in demand and therefore are considered major products. The sale of by-products should be identified in the sales reported per return, usually as cost of sales rather than gross receipts.

Miscellaneous Revenue
  1. The operator of the refinery may realize revenue from miscellaneous sources such as:

    1. Sale of steam to contiguous or nearby facilities

    2. Sale of electricity in circumstances similar to (a) above

    3. Sale of scrap materials, equipment

    4. Sale of containers, deposit recoveries

    5. Royalties, fees, and rents from patents, know-how, catalysts, and/or facilities. This revenue should be reported as gross receipts, but some items may be included in the cost of sales or netted to an expense account.

Know-How, Patents, and Royalties
  1. Research and development has created technology that is a vital commodity for the refining and petrochemical industries. The demand for proven processes and the utilization of patent rights is an important source of revenue. Investments in these intangible assets and a listing of the in-house developed know-how, patents, and processes should be analyzed:

    1. To verify the royalties and fees received from books to the return

    2. To account for additions and removals

    3. To verify the income reported from the disposition of all or an undivided interest in these intangible assets

    4. To verify that the sale/transfer to a controlled foreign corporation or other related party was correctly reported

  2. Rent or royalty income received for the use of intangible assets should include the value of any items or services received in exchange. Consideration should be given to the impact of the transactions involving these intangible assets on taxable income.

  3. Some taxpayers maintain that long term gain under the provisions of IRC 1231 be recognized upon the sale or exchange of these intangible assets. Alternatively, others propose that no ordinary income be attributed to the sale or exchange when no "tax benefit" is realized for IRC 174 expenditures made and deducted for the creation of the intangible asset. Refer to IRC 111 and Rev. Rul. 85–186 1985-2 CB 84.

  4. For patents disposed by the holder, IRC 1235 characterizes disposal as the sale or exchange of a capital asset held for more than one year IRC 1235(b). This special provision excludes the employer of the creator of the patent.

Direct Costs and Purchases — Domestic Crude

  1. A significant cost incurred by a refiner will be the purchase of feedstock (crude oil) for the manufacturing processes of the refining operations. Acquisitions of domestic crude are from two primary sources: produced and purchased. In both instances, the acquisitions are treated as purchases, inasmuch the production of crude and purchases by the refiner are from different entities or from another division of an integrated oil company. Refer to IRM 4.41.1.6.6 if problems arise in the verification of the cost figures that are used by the refinery operating entity.

Foreign Crude
  1. Foreign crude oil is a major source of supply for the operation of the refining complex. The agent should be alert to the fact that foreign crude oil, as a part of the raw material for the refining operations, can be from related producers and from unrelated suppliers. The acquisition of foreign crude can pose a problem for examiners. Foreign crude oil imports are subject to price adjustment per IRM 4.41.1.6.2.1. An international examiner or petroleum technical specialist can assist.

Finished Products
  1. Also included in the cost of goods sold, more specifically as purchases, are finished products that are acquired for use in the manufacturing operations of the refining and petrochemical industry. During examination, attention should focus on inventory sections. Refer to Exhibit 4.41.1-18 for examples of finished products.

Blending Stocks and Additives
  1. While blending stocks and additives are used for most finished products, the best known application involves gasoline. The two most important variables in gasoline blending are vapor pressure and octane number. Approximate characteristics of some blending components are found in Exhibit 4.41.1-19.

  2. Effective engine performance involves the vaporization of the gasoline. For handling cold starting, there must be enough volatile hydrocarbon in the gasoline to get a vapor-air mixture that will ignite. Measurement of volatility is vapor pressure. Common measurement is Reid Vapor Pressure (RVP), named after the man who designed the test apparatus.

    1. The RVP of gasoline must meet the extreme conditions of cold starts, normal running when warmed up, and restarting when hot. There is a direct correlation between a gasoline's ability to meet these conditions and the VP.

    2. The most suitable RVP for gasolines varies with the seasons. Cold starting in northern Minnesota's cold winters requires a gasoline with a 3-pound per square inch (psi) RVP. During the hot days of August in South Texas, cars won't restart if the RVP is higher than 8.5 psi.

    3. To avoid vapor lock, gasoline RVP may be localized to accommodate local prevailing environmental conditions as the combination of high altitudes and high temperatures can cause problems.

    4. A review of the above approximate RVP characteristics of available blending components shows that all but one have RVP's below the usual limits of finished gasoline. Therefore, n-butane is used as the pressuring agent. Refinery production of butane, plus butane recovered from natural gas in gas recovery plants, provides an ample supply of relatively inexpensive butane or gasoline blending. The amount of butane that can be added is limited due to its high RVP.

  3. The compression of the gasoline/air vapor in the engine heats the mixture, and it will get hot enough to self-ignite without the aid of a spark plug. Premature self-ignition produces knocking. The measurement of whether a gasoline will knock in an engine is in octane numbers. The most commonly known additive to improve the octane number of gasoline has been lead. The addition of tetraethyl lead (TEL) or tetramethyl lead (TML) does not affect any other properties, including vapor pressure. With the mandated phase-down in the lead content of gasoline and the introduction of unleaded gasoline, other additives are now available for octane improvements.

    1. The listed approximate octane numbers of available blending components. Refer to Exhibit 4.41.1-19 for raw stock from the processing units. With the addition of lead or other additives, some components are more susceptible to octane enhancement than others.

    2. Blending to meet octane specifications includes not only the selection of amounts of the various components, but also the octane enhancement available for each component with variable amounts of additives.

    3. It can be seen that the octane number of straight-run gasoline is quite low for finished gasoline. The addition of butane will increase the octane number, but the amount that can be added is limited by the resulting high vapor pressure. The other blending stocks are required to meet both criteria.

    4. Optimal blending of gasoline is not simple in overall refinery operations. Operational costs and seasonal availability of produced components, as well as costs of purchased components and additives, must be considered. Balancing the selection of components for both the desired RVP and octane rating requires the consideration of many alternatives.

    5. Refineries utilize computers to blend finished gasoline. On-line blending may involve computer selections of streams or blending components from individual processing units and/or intermediate storage tanks, as well as the input of additives.

  4. Additives for other than octane enhancement are commonly found in refinery operations. In some instances, chemical inhibitors or antioxidants which delay the formation of gum in gasoline are used. Coloring dyes may be used in gasolines or fuel oils. The production of lubricating oils and grease involves the use of other additives.

Exchanges
  1. The nonrecognition rules of IRC 1031 apply to like kind exchanges. However, the section provides that property held for productive use in trade or business or for investment does not include stock in trade or other property held primarily for sale. Therefore, exchanges of inventoriable goods constitute a taxable transaction.

  2. Exchange contracts of inventoriable goods are normally one of three types:

    1. Spot. A one time exchange or an exchange that is for a short period of time.

    2. Continuous Spot. A recurring short-term contract, often seasonal.

    3. Continuous. An ongoing, evergreen contract that may run for several years with no fixed expiration date.

  3. Exchanges are brought about by a need for a specific product at a specific location in a desired quantity that is not available within the system of the exchanging partner. Differentials attributable to location, handling, and grade are paid in cash and/or product.

Accounting For Exchanges
  1. There are generally three methods used within the industry to account for exchanges as follows:

    1. Exchange Inventory Method. Net balances due to or from exchange partners are merely added or subtracted from inventory balances with no gain or loss being realized until the ultimate sale.

    2. Gross Purchases and Sales Method. Each exchange receipt is treated as a purchase and each exchange delivery as a sale.

    3. Net Purchases and Sales Method. Using quantity accounting for exchange balances, end of period adjustments are made whereby favorable balances are recorded as accounts receivable and sales while unfavorable balances are recorded as purchases and accounts payable. Although this method does not recognize the limitation in IRC 1031 concerning nonapplicability to inventoriable goods, it is prevalent in the industry.

Examining Exchange Transactions
  1. The following may be helpful in determining proper treatment of like kind exchanges under IRC 1031:

    1. Ask the taxpayer to identify all material exchanges of property.

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

    3. On corporation returns, Schedule M should be considered for income not reported for tax purposes.

    4. Annual reports may footnote exchanges of property.

    5. Scan the property ledger.

    6. Ascertain the treatment of boot received by the taxpayer since boot may have been treated as a reduction in the basis of the asset received.

  2. When examining inventoriable goods not subject to nonrecognition under IRC 1031, consider the following:

    1. Ascertain the accounting treatment used by the taxpayer in accounting for exchanges and treatment of any boot received.

    2. Ascertain if the taxpayer has consistently followed the method currently being used.

    3. Review year-end exchanges to identify possible exchange contracts entered into to protect LIFO inventory layers. An exchange contract entered into at year-end to protect a LIFO layer would normally involve a reversal after year-end. The potential for abuse is greater in those instances where one exchange partner uses the exchange inventory method and the other exchange partner uses the gross purchases and sales method. In this instance, both taxpayers can, under their method of accounting for exchanges, include the same goods in physical inventory.

    4. For those taxpayers using the exchange inventory method, see Treas. Reg. 1.481–1 prior to proposing a change in method of accounting.

    5. Make sure that favorable exchange balances (inventory items owed by the taxpayer) are treated the same as unfavorable balances (inventory items owed to others).

    6. Taxpayers using the exchange inventory method can experience instances when quantities deliverable under exchange contracts exceed actual inventory amounts. This can have a material impact depending upon the LIFO pools used by the taxpayer since the LIFO inventory must be adjusted for the "negative" inventory.

    7. Ascertain if periodic adjustments have been made to adjust exchange balance accounts through sales or purchases. Periodic adjustments is a suggested accounting treatment in COPAS Bulletin No. 17, section 10 entitled, Crude Oil Trading. However, this treatment is improper for tax purposes (see PLR 8043017).

Utilities
  1. Most large refineries distribute utility costs in their internal cost accounting systems. Their controls may involve a distribution to the various processing units as well as between utilities (fuel for steam generation). Many of the smaller refineries do not distribute or allocate utility expenses, and they control their utility operations through operational reviews and budgetary analysis.

    1. With ever-increasing costs for utilities, economic operations dictate the effective and efficient use of utilities. In many locations where utility costs are allocated, the initial distribution of utility costs is based on metered volumes. In some instances, a refiner may use meters, estimates, engineering standards, or a combination of the three methods.

    2. Electricity is normally purchased from a public utility company with some standby electrical generating capacity for emergency purposes.

    3. Natural gas may be purchased for intermediate use.

    4. Refinery operations require considerable amounts of steam, and steam generating units are to be anticipated. Frequently, where refinery or petrochemical operations are contiguous, the steam generating unit in one plant will supply steam to all plants involved. With single ownership of all plants, there are no apparent tax consequences. With separate/variable ownership of the plants, a sale of steam may be involved. The contractual agreements and the allocated costs for steam should be reviewed under appropriate circumstances.

Filter Materials
  1. Filtering materials are used in the production of petroleum products to remove impurities. The agent should verify that unconsumed filtering materials are inventoried at yearend. Refer to IRM 4.41.1.6.6.1.1, Finished Products, concerning the treatment of this item in inventory.

Labor and Employee Benefits
  1. Among the other direct costs to be attributed to the finished product, as throughput of the refinery, are the labor and applicable benefits of the employees directly related to the manufacturing operations of the refining industry. The entity being examined will normally maintain cost accounting records that accumulate all factors of costs that are component cost factors of the finished product. The agent should obtain these workpapers for use in examination and verification of all included direct cost factors of the finished product.

Indirect Expenses — Depreciation and/or Amortization

  1. Since depreciation is a major area of expense, the examiner should be alert to review the appropriateness of the deduction in conjunction with the engineer.

  2. Certain incentives impact the depreciation computation and/or provide tax credits. See IRM 4.41.1.6.7.6.

Modified Accelerated Cost Recovery System (MACRS) Problem Areas
  1. Taxpayers may not use the applicable percentage stated in IRC 168(b) for recovery property used predominantly outside the United States. The determination that a property is used predominantly outside the United States is made by following the rules provided in Treas. Reg. 1.48-1(g).

  2. Are the classes of property correctly designated, including recovery property used predominantly outside the United States?

  3. Is the applicable percentage for the recovery deduction consistent with the alternative depreciation system?

  4. Refiners should use Asset Class 13.3, Petroleum Refining, for depreciation purposes. Class 13.3 has a GDS recovery period of 10 years and a class life of 16 years. An issue exists where some refiners may propose to change their method of depreciation for certain assets used in petroleum refineries to Asset Class 28.0, Manufacture of Chemicals and Allied Products. Class 28.0 has a GDS recovery period of 5 years and a class life of 9.5 years. This issue could also exist for the misclassification of new asset additions. A Field Directive on this issue was issued April 2, 2002. The Directive recommends the following 2 positions:

    • all processing assets involved in the activity of petroleum refining are to be included in MACRS Asset Class 13.3. This would include any incidental manufacturing or waste removal processes, which are integral parts of petroleum refining.

    • Where the taxpayer is engaged in more than one industrial activity, the activity of each asset’s primary use should be used for classification.

  5. Alternative Depreciation System (ADS) must be used for certain property (refer to IRC 168(g). ADS generally requires using the straight line method, the applicable convention under IRC 168(d) and a recovery period based on the class life of an asset. Examiners should look for two types of refinery assets:

    1. Any tangible property which during the taxable year is used predominantly outside the United States. Foreign real property is ADS with a recovery period of 40 year.

    2. Any tax-exempt bond financed property. Examiners have found that refiners occasionally receive tax-exempt financing for construction of equipment to process low-grade fuel supplies but fail to use the ADS method.

Patents
  1. The petroleum refining and petrochemical processes involve the use of, and the development of, high technology involving patents and patent rights. The taxpayer may obtain rights to a patent by paying a royalty fee, by purchase, or by obtaining a patent for processes developed in-house.

  2. Royalty payments usually extend over the remaining life of the patent rights obtained. Payments over a period substantially shorter than the life of the patent rights obtained may indicate that a lease purchase agreement is involved. A patent or a patent right is an intangible asset. Accelerated methods of depreciation generally may not be used for patents. See Treas. Reg. 1.167(a)-14(c)(4).

  3. Generally, the purchase price and the related costs of acquiring the patent are depreciable over the remaining life of the patent (Treas. Reg. 1.167(a)–6), or a shorter period, if it can be estimated with reasonable accuracy, Treas. Reg. 1.167(a)–3. The straight line method of depreciation is normally used. Other methods not expressed in term of years may be utilized when appropriate. See Treas. Reg. 1.167(a)-14(c)(4).

  4. The in-house development of patent rights may include research and experimental expenditures deductible under the provisions of IRC 174. The cost basis of a patent subject to depreciation includes not only the purchase price but the costs of government fees, drawings and models, materials and labor allocated to perfecting it, attorney fees and the cost of clearing the legal title, Treas. Reg. 1.167(a)–(6)(a).

  5. If the patent becomes valueless in any year before its expiration, the unrecovered cost may be deducted in that year, Treas. Reg. 1.167(a)–6(a).

  6. Areas of interest in the examination of patents and patent rights include:

    1. The review of the taxpayer's beginning of the year and end of the year record of patents and patent rights.

    2. Has taxpayer properly capitalized the costs of the patents?

    3. Does taxpayer claim excessive depreciation?

    4. Does taxpayer pay excessive royalties or fees to a controlled foreign corporation or related party that may require the application of the provisions of IRC 482?

    5. Does taxpayer sell patents in the ordinary course of business? The sale or exchange of patents is discussed in IRM 4.41.1.6.5.3.

    6. Has taxpayer transferred a patent to a controlled foreign corporation or other related party which may be reported as long term gain in error?

Catalysts
  1. The various types of catalysts used in the petroleum refining and petrochemical processes include some with a nominal cost and some that are extremely valuable. An overview of the accounting treatment, the identity of, the status of, and the use of catalysts in the refinery processes is included in IRM 4.41.1.6.1.4 and IRM 4.41.1.6.8.2.

  2. In most instances, the metal in the catalyst is not consumed, does not lose its identity, and very little, if any, is lost in the refining process. It is not subject to wear and tear, to decay, to exhaustion, or obsolescence. As such, it is not of a character subject to the allowance for depreciation under IRC 167 and IRC 168.

  3. Precious metals in the catalyst that are lost in the refining process or otherwise unrecoverable for reuse is property subject to wear and tear, exhaustion, or obsolescence. Thus, it is of a character subject to the allowance for depreciation under IRC 167 and IRC 168. These costs, in addition to the "other capitalized costs" constitute the "depreciable basis" of the catalyst. "Other" includes such items as the frame, screen, bedding, freight-in, commissions and fees related to the acquisition, and related costs to bring the catalyst to that point in time when it is ready to be placed in service.

  4. Following are some of the factors for examination:

    1. The Schedule M (Reconciliation of Income Per Books with Income Per Return) amounts should be examined for any unusual deductions claimed on the return, but not deducted in the books, that may involve catalyst depreciation.

    2. The catalyst expense included in the return (identified in the tax workpapers, working trial balance, or other) should be compared to the monthly book amount for catalyst depreciation, royalties, rents, or any unusual expenses.

    3. Taxpayer's internal controls for catalyst and the asset accounts for the inventory of catalysts should be reviewed together with the title records and agreements for royalties and rent expenses.

    4. Tax workpapers for the analysis of the inventory of catalysts such as date acquired, whether owned or leased and the depreciation computation detail.

  5. The problem areas for examination of depreciation deducted for catalysts include the following:

    1. The costs may be deducted in error.

    2. The acquisition costs and expenditures to bring the catalyst to that point in time when it is ready to be placed in service may be deducted in error.

    3. The cost of economically recoverable precious metals (and in some cases, the cost of nonprecious metals) may be included in depreciable basis in error.

    4. Determining the appropriate amount of previous metal that is ultimately recoverable for reuse vs. the amount that is not recoverable for reuse.

Certified Pollution Control Facility
  1. The taxpayer has an election to amortize over 60 months the basis of any ceritified pollution control facility; refer to IRC 169(f). See IRC 169(d)(5) for an exception of 84-month amortization period applicable to certain air pollution control facilities placed in service after April 11, 2005. It should be noted that the Federal certifying authority does not certify any property when it appears that its costs will be recovered over its actual useful life from profits derived through the waste recovery or otherwise in the operations of such property. The amortization deductions are subject to recapture to the extent of any gain on the sale of the facility; see IRC 1245(a)(3)(C).

Overhead
  1. Overhead items are those costs necessary for production which cannot be conveniently traced to a specific unit of finished product.

  2. The cost accounting system groups all such individual items together or applies them to products through the use of some allocation method and base.

  3. An improper choice of the method or base may distort income through an erroneous inventory valuation.

  4. Examiners should carefully review overhead allocations to insure that the taxpayer is complying with the uniform capitalization rules of IRC 263A. Treas. Regs. 1.263A–1 through 1.263A-3 set forth the guidelines and should be reviewed.

  5. Consideration also should be given to the impact of Treas. Reg. 1.861–8 on overhead allocations.

  6. Commonly accepted accounting terminology to use in analyzing overhead is provided in Exhibit 4.41.1-16.

  7. A good source of examination leads might be cost of production reports. An example of the contents of a cost of production report is shown in Exhibit 4.41.1-20.

Repairs
  1. Refinery repairs are normally very substantial due to the nature of refining processes. Examination focus on the most substantial amount items is recommended.

  2. Refinery repair accounts normally have a large volume of activity. Due to this large volume, it is often an area well suited for the use of statistical sampling methods to detect misclassified items. Because of the technical nature of refinery assets, the assistance of an IRS engineer is beneficial.

Turnarounds
  1. The term "turnaround" in the context of refining refers to a period of time that the refinery is shut down to perform preventive maintenance. The agent should expect to see a large portion of the yearly repair expense incurred during this brief interval of time. Depending on the process unit impacted and the amount of maintenance or repair needed, the length of turnaround can range from one to four weeks or even longer.

  2. During turnarounds, the taxpayer may be also making some capital improvements, i.e., changing out old equipment for new equipment, adding new units, etc. Even though the purpose of the turnaround is primarily to do preventive maintenance, capital expenditures may be incurred simultaneously.

  3. When analyzing whether turnaround expenditures (or any repair expenses) are capital expenditures, examiners should apply the appropriate capitalization regulations and consider the applicability of the LB&I Stand Down Directive dated March 15, 2012. Specific attention should be given to whether a turnaround:

    • is an improvement to a unit of property per Treas. Reg. 1.263(a)-3T(d);

    • results in a betterment of a unit of property per Treas. Reg. 1.263(a)-3T(h); or

    • qualifies as a safe harbor for routine maintenance expenses under Treas. Reg. 1.263(a)-3T(g).

  4. The regulations contain applicable examples and highlight potential audit areas to consider in examining turnaround expenditures. Example 9 in Treas. Reg. 1.263(a)-3T(g) "routine maintenance with betterments" illustrates that routine maintenance expenses would not qualify for the routine maintenance safe harbor if they were necessary to result in a betterment (such as, but not limited to, materially increasing capacity, productivity, efficiency, strength or quality). Example 10 "exceptions to routine maintenance" illustrates that expenses are not routine maintenance if they return a unit of property to its former ordinary efficient operating condition if the property has deteriorated to a state of disrepair and is no longer functional for its intended use.

  5. When encountering capital expenditures, the agent should determine that all related costs have been properly included in the amount capitalized. This may include removal costs of old equipment or other modifications to the plant which are necessary in order to enable the new equipment to be installed and used. The agent should ascertain that labor and indirect costs associated with the capital item have been capitalized.

Royalty and Licensing Fees
  1. The task of successfully operating refineries and petrochemical plants necessitates the use of various royalty or licensing arrangements. During the examination, the agent should be alert to the payment of these fees. Such payments may be to related entities and if so, the contracts requiring their payment should be analyzed for arm's-length pricing. The contracted arrangements for the payment of these fees are usually related to units of throughput or units of production.

  2. The payment of royalty or licensing fees become obvious and are more likely to occur when acquisition, construction, and/or expansion of plant facilities is undertaken. The agent should be alert to any advance payments of these fees that would be payable on future production as throughput in the manufacturing processes of the refining and petrochemical plants.

Tax Incentives for Refining and Use of Renewable Fuels - IRC 179B, 45H, 179C and 40A
  1. Beginning with tax year 2003 certain tax incentives for refining and use of renewable fuels were added to the IRC. These incentives include:

    • IRC 179B – Deduction for Capital Costs Incurred in Complying with Environmental Protection Agency Sulfur Regulations

    • IRC 45H – Credit for Production of Low Sulfur Diesel Fuel

    • IRC 179C – Election To Expense Certain Refineries

    • IRC 40A – Biodiesel and Renewable Diesel Credits - See Exhibit 4.41.1-31 for a brief history.

IRC 179B
  1. Deduction for Capital Costs Incurred in Complying with Environmental Protection Agency Sulfur Regulations. This provision permits small business refiners to claim an immediate deduction for up to 75 percent of the qualified costs paid or incurred when complying with EPA’s highway diesel fuel sulfur control requirements. IRC 179B was created by the American Jobs Creation Act of 2004.

  2. A small business refiner is a taxpayer in the business of refining petroleum products who employs less than 1,500 employees and had less than 205,000 barrels per day (average) of total refining runs in 2002. Examiners should be aware that the 1,500-employee test is for any day in the taxable year. In contrast, the tests involving refining runs refer to the 1-year period ending on December 31, 2002.

  3. Qualified costs are defined in IRC 45H. They include expenditures for the construction of new process units or the dismantling and reconstruction of existing process units to be used in the production of low sulfur diesel fuel, associated adjacent or offsite equipment (including tankage, catalyst, and power supply), engineering, construction period interest, and sitework.

  4. The percentage of costs allowed is reduced for amounts in excess of 155,000 barrels a day of total refinery runs.

  5. The provision is effective for expenses incurred after December 31, 2002. As a result, examiners will need to be alert for potential claims that may be filed for tax years ending after this date.

IRC 45H
  1. Credit for Production of Low Sulfur Diesel Fuel, IRC 45H. It provides a general business credit to small business refiners equal to 5-cents for each gallon of low-sulfur diesel fuel produced during the taxable year that complies with EPA sulfur control requirements. IRC 45H was created by the American Jobs Creation Act of 2004.

  2. The total production credit claimed by the taxpayer cannot exceed 25 percent of the qualified cost incurred to comply with the EPA's highway diesel fuel sulfur control requirements.

  3. Basis in the property is reduced by the amount of credit claimed.

  4. To obtain the credit, the taxpayer will have to secure certification that the qualified costs will result in compliance with EPA regulations.

  5. The provision is effective for expenses incurred after December 31, 2002 and ending on the earlier of the date that is one year after the date on which the taxpayer must comply with the applicable EPA regulations or December 31, 2009.

IRC 179C
  1. Election To Expense Certain Refineries, IRC 179C. Under present law, petroleum refining assets are depreciated over a 10-year recovery period using the double declining balance method. Section 179C provision provides a temporary election to expense 50 percent of the cost of qualified refinery property. Any cost so treated is allowed as a deduction for the taxable year in which the qualified refinery property is placed in service. The remaining 50 percent is recovered under present law. IRC 179C was created by Energy Policy Act of 2005.

  2. Temporary regulation section 1.179C-1T was issued on July 3, 2008. Shortly thereafter the Energy Improvement and Extension Act of 2008 extended the provisions of section 179C by two years and also modified the provisions in sections 179C(d) and 179C(e)(2) dealing with shale and tar sands.

  3. In general “qualified refinery property” means any portion of a qualified refinery that is located in the United States and which is used for the primary purpose of processing liquid fuel from crude oil or qualified fuels as defined in IRC 45K(c ), or directly from shale or tar sands.

  4. Specific rules regarding the property include:

    Rule Date Placed in Service
    original use commences with taxpayer after August 8, 2005 and before January 1, 2014
    meets all applicable environmental laws in effect placed-in-service date
    increases the capacity of an existing refinery by at least 5 percent or which increases the percentage of total throughput attributable to qualified fuels such that it equals or exceeds 25 percent not a factor
    with respect to the construction of which there is a binding contract in the case of self-constructed property, the construction of which began after June 14, 2005 and before January 1, 2010

  5. The increased capacity requirements refer to the output capacity of the refinery, as measured by the volume of finished products other than asphalt and lube oil, rather than input capacity as measured by rated capacity. It would be determined as of the date the property is placed in service. Any reasonable method may be used to determine the baseline capacity and to demonstrate and substantiate the required increase in capacity.

  6. The expensing election is not available with respect to identifiable refinery property built solely to comply with federally-mandated projects or consent decrees. For example, a taxpayer may not elect to expense the cost of a scrubber, even if the scrubber is installed as part of a larger project, if the scrubber does not increase throughput or increased capacity to accommodate qualified fuels and is necessary for the refinery to comply with the Clean Air Act. This exclusion applies regardless of whether the mandate or consent decree addresses environmental concerns with respect to the refinery itself or the refined fuels.

  7. A taxpayer may not claim a deduction under section 179C for any taxable year unless it files a report as specified in the regulations with respect to the operation of the taxpayer's refineries. Generally the taxpayer would attach the report to its filed tax return in the year the property is placed in service.

  8. Effective Date: The provision is effective for property placed in service after August 8, 2005, the original use of which begins with the taxpayer, provided the property was not subject to a binding contract for construction on or before June 14, 2005.

IRC 40A
  1. Credit for Biodiesel and Renewable Diesel Used As Fuel, IRC 40A. This section provides a $1.00 per-gallon credit (reportable as a General Business Tax Credit) relating to the following fuels: biodiesel, agri-biodiesel, renewable diesel, biodiesel included in a biodiesel mixture, agri-biodiesel included in a biodiesel mixture and renewable diesel included in a renewable diesel mixture. This is a complex area with many rules and limitations. Figure 4.41.1-1 defines some key terms. Consult an Energy Credit Technical Specialist if you need further guidance.

    Figure 4.41.1-1

    Terminology and Computation of Biodiesel and Renewable Diesel Fuel Credits

    Term Definition Computation of Credit
    Biodiesel Monoalkyl esters of long chain fatty acids derived from plant or animal matter which meet the registration requirements for fuels and fuel additives established by the Environmental Protection Agency under section 211 of the Clean Air Act (42 U.S.C. 7545), and the requirements of the American Society of Testing and Materials D6751 $1.00 per gallon credit which during the year was used as a fuel in a trade or business, or sold at retail to another person and put in the fuel tank of that person's vehicle. No credit is allowed for fuel used in a trade or business that was purchased in a retail sale. A credit of $1.00 per gallon is only available by the producer or sold in a trade or business as a fuel to another person.
    Renewable Diesel Diesel fuel derived from biomass which meets the registration requirements for fuels and fuel additives established by the Environmental Protection Agency under section 211 of the Clean Air Act (42 U.S.C. 7545), and the requirements of the American Society of Testing and Materials D975 or D396, or other equivalent standard approved by the Secretary Same as for Biodiesel Credit
    Agri-biodiesel Biodiesel derived solely from virgin oils, including esters derived from virgin vegetable oils from corn, soybeans, sunflower seeds, cottonseeds, canola, crambe, rapeseeds, safflowers, flaxseeds, rice bran, mustard seeds, and camelina, and from animal fats $.10 per gallon credit for each gallon of qualified agri-biodiesel produced by any eligible small agri-biodiesel producer. To qualify for the credit, the agri-biodiesel must be sold by such producer to another person for a) use by such other person in the production of a qualified biodiesel mixture in such other person's trade or business (other than casual off-farm production); or b) use by such other person as a fuel in a trade or business. A qualifying producer may also sell such agri-biodiesel at retail to another person who then places it in the fuel tank of such other person.

    Note:

    Small producers have capacity less than 60,000,000 gallons. Eligible producers have a limit of 15,000,000 gallons.

    Qualified mixture Combines biodiesel or renewable diesel with diesel fuel determined without regard to any use of kerosene. Kerosene should be treated as diesel fuel when figuring a renewable diesel mixture credit for certain aviation fuel

  2. The Biodiesel and Renewable Diesel Fuels Credit is claimed by completing Form 8864. A certification form from the producer or reseller identifying the product produced and the percentage of biodiesel and agri-biodiesel in the product must be attached to the Form 8864.

  3. Limitations and Special Rules. For pass-through entities, the 15,000,000 and 60,000,000 gallon limits are applied at both the entity level and at the partner or similar level. All members of the same controlled group of corporations (within the meaning of section 267(f)) and all persons under common control (within the meaning of section 52(b) but determined by treating an interest of more than 50 percent as a controlling interest) are treated as one person. The amount of the Biodiesel and Renewable Diesel Fuels Credit under IRC 40A is properly reduced to take into account any excise tax credit benefit provided with respect to such biodiesel. The Biodiesel and Renewable Diesel Fuels Credit is not applicable to any biodiesel which is produced outside the United States for use as a fuel outside the United States. Taxpayers are liable for excise tax on biodiesel and renewable diesel sold for use in a diesel-powered highway vehicle. The excise rate is 24.4 cents per gallon and is filed quarterly on Form 720, Quarterly Federal Excise Return.

  4. Examination Techniques. Examiners should be aware that the Biodiesel and Renewable Diesel Fuels Credits are includible in gross income under IRC 87 and IRC 40A. If the Taxpayer filed a Form 8864 for the Biodiesel and Renewable Diesel Fuels Credit, a compliance check of the Taxpayer's Form 720, Quarterly Federal Excise Return, should be made to determine if there are duplications in claiming both the biodiesel credit and the excise tax credit. There are recapture provisions under IRC 40A(d)(3) if the biodiesel or biodiesel mixture is not used as fuel or if the biodiesel is separated from the biodiesel mixture. The Energy Credit or Agriculture Subject Matter Experts can be contacted for additional trends, examinations techniques and directives. The instructions for completing Form 8864 should be reviewed for additional limitations, definitions and revisions.

Joint Operations

  1. The petroleum industry has a long history of using joint operations as a vehicle for its activities. The basic premise involved in the examination of joint operations is the classification of the organization as a partnership, an association taxable as a corporation, or merely a tenants-in-common co-ownership.

  2. A tenants-in-common arrangement usually involves the mere co-ownership of property that is maintained, kept in repair and rented, or leased with no operations involved. Such an arrangement is not considered a partnership, Treas. Reg. 301.7701–1(a)(2).

  3. The participants in joint operations are pooling their resources, know-how, and services for the purpose of sharing the risk and the potential economic rewards. The operator of the refinery may be involved in several different joint operations.

  4. The construction of plants for further manufacturing of refinery products frequently involves joint operations. The refinery products that constitute resource material for fertilizers, chemicals, plastics, etc., may be the subject of the joint construction of a plant and/or the joint operations of such a plant or facility. The instruments governing the joint operations provide authority for the construction and/or the management of the facility, the conduct of the operations, and the division of the profits and losses, or the delivery of the plant products.

  5. Occasionally, the participants organizing the joint operations as tenants-in-common for sharing expenses, etc., find that, in fact, they meet the standards requiring the organization to be recognized as a partnership. Under certain circumstances the participants may qualify to be excluded from the provisions of Subchapter K of the Code regarding the requirement to file partnership returns. The most common organization formed in a joint operating arrangement is the partnership entity, IRC 7701(a)(2).

Areas of Interest in Examination of Joint Operations
  1. If a partnership return has been filed, the control of the returns of the participants should be inaugurated as early as possible in the examination process so the determination may be uniformly applied and the statute of limitations protected.

  2. If a partnership return has not been filed, information reports should be disseminated as early as possible in the examination to ensure uniform application of the determination of a potential issue and to protect the statute of limitations.

  3. Does the co-ownership arrangement constitute an "association" taxable as a corporation?

  4. If the joint operations qualify as a "partnership," have the partners made an election to be excluded from the provisions of Subchapter K?

  5. Do the partners jointly sell the "partnership," products which may negate the election to be excluded from Subchapter K?

  6. Does the partnership have "startup" expenditures that should be capitalized?

  7. Are the organization expenditures properly capitalized?

  8. Do any of the partners have losses allocated to them in excess of their adjusted basis in the partnership per IRC sections 704(d) and 705?

  9. Does the operator of the refinery engage in any activity described in IRC 465(c) subject to the at-risk rules in IRC 465?

Types of Catalysts
  1. As discussed in IRM 4.41.1.6.1.4, many substances are used as catalysts. The royalty or licensing agreement for use of a particular type processing unit may also include an agreement for use of the designer's catalyst or any subsequently developed catalyst for the unit. The catalyst may be purchased or rented from parties other than the designer/licenser of the processing unit. The refiner may design its own processing unit and manufacture its own catalyst or purchase/rent the catalyst on the open market.

  2. It is not feasible to establish guidelines based on the type processing unit or on the content of the catalyst alone. Similar processing units will utilize different catalysts in different refineries. Sometimes the catalyst in a particular unit will be switched to a new improved variety. The catalyst for a particular process at one installation may involve precious metals while at another installation the precious metals are absent. One installation of a particular type process may use a liquid catalyst while another installation uses a solid catalyst with differences in operational factors. Analysis based on catalyst content alone is insufficient, as operational factors often are more indicative of proper accounting treatment.

  3. As shown in Exhibit 4.41.1-21, the named processing units are indicative of the type of process involved. For each type process, there are different licensed processes available with variables in type of catalyst, type of reactor, method of regeneration (if applicable), method and timing of catalyst recharging, and other processes.

  4. Particle size of solid catalyst varies by the type of operation. In fixed bed reactors, the catalyst stays put in a chamber (reactor), and the hydrocarbon flows through or is dribbled through the catalyst. An extended residence time is usually found where fixed bed reactors are involved. Frequently, there are several reactors, and a cyclic operation is involved. Where regeneration is involved, several reactors may be on stream (processing the hydrocarbons) while others are in a regeneration cycle (burning off the carbon) or in a recharging cycle. The size of the catalyst in fixed bed reactors is larger than in moveable bed reactors.

  5. With moveable beds, both the hydrocarbon and the solid catalyst flow through the reaction chamber. In catalytic cracking, after a very short residence time, the mixture is separated with the catalyst circulated to the regeneration chamber. The type catalyst is generally bead or particle.

    1. The beads are approximately 1/8 to 1/4 inch in diameter and extremely porous to provide extensive reaction surface area. The small size permits movement through the chambers. Beads are not now as acceptable, as particles are more effective.

    2. The particles are much smaller and have the appearance of fine sugar or baby powder. The particle type (it also is very porous) is now more prevalent due to its fluidity. If the particles are placed in a container and the container is tilted or shaken, they react just like a fluid (liquid). The nomenclature, fluid catalytic cracker, is with reference to particle type catalysts. This type cracker utilizes the enhanced fluidity/mobility for internal movement of the catalyst through the reactor, regenerator, or other component.

  6. One example of the use of liquid catalysts is in alkylation units where the catalyst is usually sulfuric acid or hydrofluoric acid. The mixture of hydrocarbons and acid is pumped through a battery of chilled reactors to provide an extended residence time. The mixture then moves to a vessel (acid settler) where no mixing takes place, and the acid and hydrocarbons separate like oil and water. As the acid circulates through the process, it gets diluted with water and picks up tar. As the acid concentration declines, it is partially drawn off, and it may be sent back to the acid supplier for refortification (purification). Internal regeneration of the catalyst is not found in this type process. The partial withdrawal of a diluted catalyst, with additions of a fresh catalyst, is an ongoing operation. It should be noted that some alkylation units utilize a solid catalyst, rather than a liquid catalyst.

  7. The reclamation costs for some catalysts may be so great, in relation to the original purchase price, that they are dumped when their effectiveness declines. Some catalysts may be used up in the manufacturing process in one way or another, even though they do not enter into the reaction itself.

  8. The use of catalysts is also involved in petrochemical operations. The production of ammonia (NH3) provides an example of the extensive use of catalysts in the petrochemical field. As seen in the above formula, ammonia contains one part nitrogen and three parts hydrogen. In many installations, the source of the nitrogen is air, and the source of the hydrogen is methane gas. The liquefaction and separation of nitrogen from air do not involve a catalyst. A mixture of methane and steam flow through furnace tubes packed with a catalyst to produce a stream of hydrogen, carbon dioxide, steam, and carbon monoxide. This stream then flows through a vessel packed with a catalyst for shift conversion of the carbon monoxide to carbon dioxide (with the generation of additional hydrogen). The produced hydrogen is separated and proportionately mixed with the nitrogen for conversion to ammonia. Such conversion requires high pressure and a catalyst. If the subsequent production of nitric acid is involved, a catalyst is also involved.

Accounting Treatment
  1. There are often tax accounting inconsistencies in proper capitalization, depreciation, or treatment when catalysts are involved. The internal accounting instructions and procedures for catalysts (for unit cost accounting or financial accounting) of different companies vary. However, an understanding of general internal accounting procedures may be helpful in clarifying the treatment of catalyst costs. An understanding of a particular taxpayer's internal accounting procedures is essential in the agent's examination of the taxpayer.

  2. In most cases, a company will have specific procedures when catalysts with precious metals are involved. This is due to the significant costs involved and the arrangements for reclamation with credit for the precious metal(s). A single processing unit may require several million dollars worth of such catalysts.

    1. The precious metal content alone may comprise 50–65 percent of the total cost of such catalysts. The balance of the total cost would be the manufacturer's production fee, freight, and sometimes a royalty fee.

    2. When the catalyst is purchased, the total cost may be charged to a prepaid inventory account. Later, when the catalyst is issued to the process unit, a cost may be capitalized and amortized for internal unit cost accounting purposes or deducted as a current expense. The amortized cost may be the total cost, or it may be a net cost (total cost, less original metal cost or less salvage value of the metal and projected reclamation costs).

    3. Some companies may maintain the original charge is inventory on an indefinite basis and expense/amortize only the replacement quantities.

    4. It should be noted that some refiners may own excess quantities of the precious metal itself or of such catalysts, and they are sometimes rented to other companies.

  3. While those metallic base catalysts without precious metals are less costly, in many instances the cost is still substantial. As such, with reclamation and credits for spent catalysts, the nonprecious base metal(s) may require the same treatment as precious metal(s).

  4. Beyond special procedures for precious metals, some companies will (for unit cost accounting purposes) segregate catalysts based on operational differences: those that are used in quantity each month or those that are used in quantity every 12–24 months or a further extended period.

    1. Monthly utilization (make-up) might be found at some cracking units or alkylation units. Some of the catalyst is regularly partially withdrawn and is either reclaimed, sold at its salvage value, or junked. The original charge of such catalysts is normally capitalized to the cost of the processing unit and amortized (for unit cost purposes) over the useful life of the unit. The reason for such treatment is that there always is an equivalent amount of catalyst in the unit. The net cost of a fresh catalyst added (make-up) is normally expensed. Some refiners may expense the original charge for unit cost purposes.

    2. Extended utilization, without significant make-up between recharges, might be found at a reformer where the catalyst may have an effective life of 12–18 months and only small quantities are added between turnarounds. At the end of the operating period, the entire catalyst charge is removed and either reclaimed or sold for its salvage value. For unit cost accounting, some companies may expense the initial charge, as well as any subsequent additions. Others may amortize the initial charge over the life of the unit or over the effective life of the catalyst itself. From a unit cost accounting viewpoint, the preferable method would be to amortize the net cost (after crediting the cost for the salvage value of the spent material) over the effective life of the catalyst itself. With complete replacement at turnarounds, the amortization of the initial charge over the life of the unit is illogical for unit cost accounting (i.e., complete replacement at 12 months versus a unit life of 15 years).

    3. It should be noted that some catalysts have an effective life of many years before recharging is required.

  5. Proper accounting for catalysts must include coordination of the amount capitalized, the appropriate life, the accountability of reclamation credits, and treatment of sales proceeds or salvage value of spent catalysts.

Depreciation
  1. Depreciation in refinery operations is discussed in IRM 4.41.1.6.7. Exhibit 4.41.1-21 provides some useful examination techniques for catalyst accounts.

  2. It is not feasible to provide guidelines for a specific processing unit or specific catalyst. However, with some understanding of how catalysts are used and with a review of the taxpayer's internal product cost accounting, the examiner should be able to properly resolve any problem areas. Engineering assistance is available for resolving questionable areas.

  3. The precious metal used in the catalyst is not consumed and very little is ever lost. To the extent that the precious metal is not used or ever lost, it is not subject to exhaustion, wear and tear or obsolescence and therefore not depreciable.

  4. The following authorities are frequently cited when precious metal catalysts are involved:

    1. Rev. Rul. 90-65, 1990-2 CB 41, provides that the refiner's platinum is economically recoverable for reuse in its business with no loss of utility, the capitalized platinum is not depreciable. the cost of any platinum not recovered is a material or supply expense under IRC 162

    2. Rev. Rul. 97-54, 1997-2 CB 23, provides that the cost of recoverable line pack gas or recoverable cushion gas is not depreciable, but the cost of unrecoverable line pack gas or cushion gas is depreciable under IRC 167 and 168

    3. In Shaughnessy v. Comm'r, 332 F.2d 1125 (8th Cir. 2003) the court addressed the use of molten tin to manufacture flat glass. The court held that the tin underwent "exhaustion and wear and tear" within the meaning of IRC 167 and the initial volume of tin was subject to depreciation under IRC 168. If examiners encounter an issue where taxpayers are relying on this case to depreciate their precious metal catalyst, examiners should distinguish the facts of the precious metal catalyst used and cite Rev. Rul. 90-65, 1990-2 CB 41, which specifically describes the treatment of precious metal catalysts. In Rev. Rul. 90-65 (Situation 2), a petroleum refiner used a catalyst, which was over 50 percent composed of platinum. Of the spent catalyst (15-20 percent), 80 to 85 percent of the platinum was recovered and included in a refabricated catalyst. The Ruling explained that "because the refiner’s platinum is economically recoverable for reuse in its business with no loss of utility, the capitalized platinum is not depreciable" . Examiners should consider contacting their Local Counsel and the appropriate Technical Subject Matter Experts. Examiners should also be aware that taxpayers might be taking such positions on Form 3115, Change of Accounting Method.

  5. Excluding the cost of recoverable precious metals (and in some cases, the cost of nonprecious metals), the cost of nonrecoverable previous metals and the other capitalized costs of the catalyst charged to a process unit are depreciable. The Taxpayer has the burden of establishing the useful life of the nonrecoverable precious metals. for example, where a taxpayer sends a spent catalyst for precious metal reclamation so that the precious metals in the catalyst are recovered for reuse, a taxpayer may be able to prove that a certain percentage is lost per a reclamation cycle. Over the course of several reclamation cycles, the taxpayer may be able to prove that a certain amount is lost over a measurable period of time. In regards to the other capitalized costs of the catalyst charged to a process unit, the useful life may be either the life of the processing unit or the life of the catalyst.

  6. Examiners should be aware that as of this IRM revision, the Office of Chief Counsel, Income Tax and Accounting division, has tentatively decided to revoke Rev. Rul. 75-491 and Rev. Rul. 90-65. Published guidance discussing these matters is forthcoming. Examiners are advised to consult their Local Counsel and the appropriate Technical Subject Matter Experts for the latest guidance.

Extraordinary and Casualty Losses
  1. Refineries are prone to have fires and explosions occasionally due to the inherent nature of refining operations and the highly volatile nature of the products involved.

  2. The agent should check local publications, company news items, annual reports, and SEC filings for such losses.

  3. If an extraordinary loss has occurred in a year under examination, the agent should determine if there has been a write-off concerning the casualty loss.

  4. Any casualty loss claimed should be verified to determine that the write-off is limited to the property lost in the casualty and that proper consideration has been given to potential insurance recoveries. Treas. Reg. 1.165-7(b) prescribes that the deductible casualty loss is the lesser of the amount of the loss (as determined per the two methods in Treas. Reg. 1.165-7(a)(2)) or the amount of the adjusted basis of the property involved. The two methods for determining the amount of the loss are generally:

    1. competent appraisal of the change in fair market value before and after the casualty and

    2. the cost of reasonable repairs to return the damaged property to the condition prior to the casualty. Refer to Treas. Reg. 1.165-7(a)(2) for more detail.

  5. The casualty loss may involve lawsuits and damages of property owned by unrelated parties. The agent should check for contingency reserves which have been set up for the possible liability resulting from the casualty.

  6. Two of the more disputed issues with casualty losses are:

    1. the interplay of IRC 162 and IRC 165 for casualty repair expenses and

    2. single, identifiable property ("SIP" ) related to the basis limitation. Both are discussed below.

Interplay of IRC 162 and IRC 165 for Casualty Repair Expenses
  1. Directive issued April 27, 2007 alerts the field of a growing trend in the utilities and telecommunications industries whereby some taxpayers are deducting casualty losses under IRC 165 and also deducting the cost of restoring the damaged property as repair expenses under IRC 162. The Service's position is that a taxpayer cannot take a casualty loss deduction and a business repair deduction as a result of the same casualty. If a casualty loss is taken, the repairs must be capitalized under IRC 263(a). Refer to Generic Legal Advice Memorandum 200606 (AM 200606), which primarily cites Rev. Rul. 71-161, 1971-1 C.B. 76..

  2. The Service's position was formally stated in the temporary capitalization regulations, generally effective January 1, 2012. Taxpayers must capitalize amounts paid to restore a unit of property per Treas. Reg. 1.263(a)-3T(i). The regulation further clarifies that repairs of damage to a unit of property resulting from or relating to a casualty loss under IRC 165, for which the taxpayer has properly taken a basis adjustments, are restorations. Thus, these repair expenses related to casualty losses are restoration expenses and should be capitalized. for more assistance on capitalization regulations and casualty losses, examiners should contact Local Counsel or the appropriate Subject Matter Expert.

Single Identifiable Property (SIP)
  1. Directive issued June 19, 2009 provides guidance to the field in determining the SIPs that may be used by an electric utility for its transmission and distribution properties, in calculating its casualty losses under IRC 165. Some taxpayers have designated their entire utilities transmission and distribution system or their entire telecommunication system as the SIP.

  2. The rationale of the "single, identifiable property" rule is to arrive at a logical, reasonable, and practical unit for valuation and accounting purposes, while preventing the borrowing of basis from unharmed property, without segregating the damaged property into artificially small subunits. In making these determinations, the field should consider the specific facts and circumstances of the taxpayer, taking into account the factors utilized by the courts as summarized in TAM 200902011.

  3. Factors listed in TAM 200902011 to be considered in determining a SIP include:

    • whether the unit chosen is reasonable in relation to the nature and scope of the casualty;

    • whether it reflects all the physical damage caused by the casualty;

    • whether it remains constant and identifiable for tax purposes, and has a cost or adjusted basis that is not changed except by elimination of an asset or by injection of capital;

    • whether it is consistent with the taxpayer's other tax accounting practices;

    • whether it is accounted for and identifiable as a unit for non-tax accounting purposes;

    • whether it is a unit whose utility derives from its functioning as a whole;

    • whether it is separately treated for operational and management purposes;

    • whether it is a commercially segmentable unit likely to be bought or sold as such; and

    • whether it is consistent with industry practice.

  4. For casualty losses involving damages to refinery assets, an IRS Engineer should be consulted in determining the appropriate SIP and the adjusted basis of those assets.

  5. Most refineries are comprised of a mixture of very old assets that are fully depreciated and newer assets with substantial remaining basis. Examiners should pay particular attention to taxpayers that are "borrowing basis" from assets not involved in the casualty by proposing an inappropriately large SIP. For example, it would be inappropriate to treat an entire refinery as the SIP even though the damage is limited to older assets that are not functionally related to the new assets. Nearly all refineries have redundancy for important assets, and often operate with substantial assets out of service for maintenance.

Abandonments and Discontinued Operations
  1. Examiners should insure that any deductions for property claimed to be worthless are valid.

  2. Examiners should ascertain whether the plant has actually been closed permanently or is merely being placed on a standby basis. This can often be determined in the following ways:

    1. A review of corporate minutes or other internal documents should ascertain who authorized the shutdown or abandonment.

    2. A review of maintenance expenses could disclose extensive maintenance not normally present in an abandoned plant.

    3. Contacts with local taxing authorities will often provide data as to any changes in assessed valuation of property in question.

  3. In the event the taxpayer claims the loss as a result of suits brought by environmental groups or agencies, the examiner should ascertain the status of pending appeals.

  4. Examiners should insure that property held to be abandoned is not being offered for sale.

  5. When facilities are shutdown (abandoned or placed on standby) and the expensive catalysts are recovered, was proper tax accounting treatment given to the recovery and disposition of such catalyst?

  6. Examiners should also be certain to review Schedule M for any possible differences between book and tax treatment.

Fines, Penalties, and Payments in Lieu of
  1. Fines and Penalties can be common in the oil and gas industry because of the nature of operations, especially for refineries. Most commonly, they are due to violations of EPA (http://www.epa.gov/) regulations on atmospheric emission or discharge into waterways or groundwater. However, they can also be due to violations of OSHA (http://www.osha.gov/) safety rules. The upstream segment could have fines or penalties related to underpaid oil and gas royalties from production on federal or Indian lands.

  2. No deduction is allowed for any "fine or similar penalty" paid to a government for the violation of "any" law, IRC 162(f) as enacted by Public Law 91–172 (1969). The Senate Finance Committee made the following statement regarding IRC 162(f) in comments explaining section 310 of the Revenue Act of 1971, P.L. 92–178, "In approving the provisions dealing with fines and similar penalties in 1969, it was the intention of the committee to disallow deductions for payments of sanctions which are imposed under civil statutes but which in general terms serve the same purpose as a fine exacted under a criminal statute."

  3. Treas. Reg. 1.162–21(b) provides that a fine or similar penalty includes an amount paid or incurred in settlement of the taxpayer's actual or potential liability for a fine or a penalty (civil or criminal). However, civil compensatory or actual damages are not fines or penalties and are therefore deductible under Treas. Reg. 1.162-21(b)(2). In contrast, punitive damages are not deductible.

    Note:

    Criminal fines and penalties are always non-deductible, even if remedial in nature. Refer to Allied-Signal Inc. v. Commissioner , CIR TC Memo. 1992-204

    .

  4. It should be noted that a payment in lieu of a fine, or a payment made as a compromise of such a liability takes on the character of the underlying asserted obligation and it is similarly nondeductible, Adolph Meller Company F2d 1360 (Ct. Cl. 1979). Amounts deducted as contributions may, in fact, be made as a settlement of, and in lieu of, a penalty or under an agreement for nonprosecution involving a fine or a penalty (civil or criminal). It is well established that, "a contribution or gift, for the purpose of section 170, is a voluntary transfer of money or property made by the transferor without receipt or expectations of financial or economic benefit." , Rev. Rul. 76–257, 1976–2 CB 52 and Rev. Rul. 79–148, 1979–1 CB 93 determined that the amount paid by the taxpayer to the charitable organization in satisfaction of a judgment or as a condition of probation by a federal district court is "not deductible under IRC 162(a) of the Code because the amount paid was a fine for purposes of section 162(f)." Furthermore, this ruling holds that such a payment does "not qualify as a charitable contribution, it is not deductible under section 170 of the Code."

  5. The examiner should be alert to identify fines and penalties which may be erroneously classified and/or inadvertently claimed as a deduction. Also, a deduction claimed in subsequent year(s) via a Schedule M adjustment requires a review of the earlier year's basis for the payment.

Settlements of Environmental Law Violations
  1. Are settlements punitive or remedial? Under the "Origin of Claim Doctrine" , examiners should first look to the underlying statute to see if its purpose is punitive or remedial. Legislative history can provide guidance. If a statute is both punitive and remedial or compensatory, or if the lawsuit covers both statutes, then the examiner should obtain and review the settlement agreement. If the settlement agreement is not clear on penalties, requesting the original lawsuit can clarify. If no lawsuit was filed, then review all the facts and circumstances through documents, testimony, or substantiating material. The burden is on the taxpayer to support any amounts deducted as compensatory. Refer to Talley Indus. v. Comm'r, CIR TC Memo 1999-200.

  2. Subject to the EPA's discretion, as part of the settlement, an alleged violator may voluntarily agree to perform an environmentally beneficial project in exchange for mitigation of some or the entire proposed penalty. These projects are generally called Supplemental Environmental Projects (SEPs) or Beneficial Environmental Projects (BEPs). Examples include:

    • purchase and donation of land for conservation purposes

    • restoration of damaged habitat

    • implementation of public health projects such as mobile asthma clinics

    In addition, violators have been required to add pollution control equipment to their plants, build water treatment plants or construct other types of real or personal property as part of a SEP.

  3. The tax treatment of SEPs is the subject of a Coordinated Issue Paper http://www.irs.gov/Businesses/Coordinated-Issue---All-Industries---Supplemental-(Beneficial)-Environmental-Projects-(SEPs). The paper concludes that a portion of the costs incurred or amounts paid by a taxpayer for the performance of a SEP or similar project under federal or state law may be analogous to a non-deductible fine or similar penalty defined under IRC 162(f). The paper further clarifies that in order to determine whether any of the amounts incurred for the SEP constitute payments in settlement of a non-deductible fine or penalty, the analysis must focus on the nature of the liabilities that results in the SEP, and not the taxpayer's motives for proposing or accepting the SEP or the benefits of SEPs to other parties.

  4. Examiners can locate taxpayer specific environmental penalty information at http://www.epa.gov/compliance/data/systems/multimedia/echo.html

Obtaining Case Documents from DOJ and EPA
  1. IRS subject matter experts liaise with Department of Justice for False Claims Act (FCA) cases or the Environmental Protection Agency attorneys to obtain documents such as settlement agreements. Examiners can search the intranet for current contacts for these agencies and request assistance in obtaining documents not otherwise provided by the taxpayer.

  2. For False Claims Act (FCA) cases settled by the Department of Justice (DOJ), certain procedures apply:

    1. The subject matter expert makes the initial request to DOJ. Then the expert provides the examiner the DOJ attorney contact so specific follow-up and details about the penalties and settlement agreement can be obtained.

    2. A Financial Management Information System (FMIS) report may be requested which shows DOJ's disbursement of funds received from the taxpayer to various federal agencies and regulators. In royalty cases, the report may not be as helpful in determining how much of the settlement amounts were single or multiple.

    3. Refer to http://www.irs.gov/Businesses/Industry-Director-Directive-on-Government-Settlements-Directive-%232 for more guidance on FCA issues.

Pipeline Right of Way

  1. Effective March 8, 1971, the Service modified an earlier ruling and announced its current position on high pressure natural gas pipeline right of way easement, clearing, and grading costs. Refer to Rev. Rul. 71–120, 1971–1 CB 79. The same position was announced for crude oil and petroleum products pipeline costs in IRC 71–448, 1971–2 CB 130.

  2. These rulings hold that easement costs (including aerial reconnaissance, preliminary surveys, roddage fee payment to the grantor based on length of the easement, crop damage reimbursement, legal fees, title work, abstract and recording fees) have a determinable life measured by the useful life of the pipeline and are, therefore, depreciable. Since easement costs are similar to a license or franchise, they are considered an intangible asset and will not qualify for any accelerated depreciation. Depreciation of right of way costs must be calculated using the straight line method. See Panhandle Pipe Line Co. v. U.S., 408 F2d 690 23 AFTR 2d 933 (Ct. Cl. 1969).

  3. Rev. Rul. 72-403, 1972-2 CB 102, holds that clearing and grading of the right of way are part of the pipeline construction costs and, as such, qualify for accelerated depreciation methods and investment credit when applicable and that initial clearing and grading are not included in any of the asset guideline classes for ADR purposes. Under Rev. Proc. 87-56 1987-2 CB 674 (for MACRS property), initial clearing and grading land improvements as specified in Rev. Rul. 72-403, are excluded from asset class 00.3, Land Improvements, asset class 46.0, Pipeline Transportation, and asset class 49.24, Gas Utility Trunk Pipelines and Related Storage Facilities. The American Jobs Creation Act of 2004 added IRC 168(e)(3)(E)(v), which provides that 15-year MACRS property includes initial clearing and grading land improvements with respect to gas utility property.

  4. The costs for the easement and for clearing and grading referred to above do not include expenditures incurred to keep the right of way clear and the pipeline in its normal operating state. Whether such expenditures are ordinary and necessary expenses or capital expenditures requires a determination based on facts and circumstances of each case.

Inventory in the Pipeline

  1. In order to maintain pressure and effect uninterrupted flow or transportation of natural gas to purchasers through pipelines, it is necessary to maintain a certain volume of gas in the lines at all times. This volume of gas is called "line pack" by the industry. Some taxpayers will expense this cost as ordinary and necessary business expense. Some may attempt to capitalize this cost as part of the pipeline cost and depreciate it over the life of the pipeline.

  2. Charges incurred by retail gas utilities obtaining natural gas for resale are includable inventory costs. These costs include damage charges, capacity charges, injection charges, storage charges, withdrawal charges, delivery charges, among others. Refer to Rev. Rul. 66–145, 1966–1 CB 98.

  3. While it is true that only oil will be flowing through the pipeline, different grades of oil may be in the pipeline at the same time. It is possible to space different grades of oil by running a cleaning tool (called a pig) and a water spacer between each type of oil. In this manner, it is possible to have many different types of petroleum products in the pipeline at yearend. Therefore, it is necessary to determine, with the help of a petroleum engineer, not only the quantity of the oil in the pipeline but also the type of oil. Once the quantity of the specific types of oil is determined, then the correct price must be applied to arrive at the correct ending inventory.

  4. In examining a pipeline, the agent should first determine what type of line is in use (gas or oil). Determine how the taxpayer handles the line pack or oil in the line expensed, capitalized or inventoried. If the costs are inventoried, determine whether all costs pertaining to the inventory are included. If the taxpayer has an oil line, ensure that the costs taken into inventory reflect the correct costs based on the correct type of oil. It is possible that the taxpayer, while correctly including the oil in inventory, may have assigned one cost for the entire oil in the pipeline while, in reality, different prices should have been used since different oils were in transit at year end.

Alaska Pipeline Depreciation

  1. IRC 168(e)(3)(C) defining 7-year property includes any Alaska natural gas pipeline. The term "Alaska natural gas pipeline" refers to the pipe, trunk lines, related equipment, and appurtenances used to carry natural gas but does not include any gas processing plant located in the state of Alaska which has a capacity of 500 billion Btu of natural gas per day and is placed in service after December 31, 2013. If the system is placed in service prior to January 1, 2014, the taxpayer may elect to treat the system as placed in service on January 1, 2014 to qualify for the 7-year recovery period. If placed in service prior to January 1, 2014 and the election is not made, taxpayer would have a 15- or 20-year recovery period depending on when it was placed in service. If elected, depreciation would not begin until after 2013.

  2. This incentive provision is effective for property placed in service after December 31, 2004.

Natural Gas Line Depreciation

  1. Gas distribution lines must be depreciated over 20 years or 15 years depending on when placed in service:

    • Placed in service on or before April 11, 2005 - 20 years

    • Placed in service after April 11, 2005 - 15 years

      Note:

      The 15 year provision (Energy Policy Act of 2005) does not apply to property subject to a binding construction contract or self-constructed on or before April 11, 2005.

    • Placed in service on or after January 1, 2011 - 20 years

  2. Natural gas gathering lines must be depreciated over a 7-year recovery period (14 year class life) under the Energy Policy Act of 2005. In addition, the Energy Policy Act of 2005 provides for no adjustment for the allowable amount of depreciation for alternative minimum tax purposes. The 7-year provision does not apply to any property which the taxpayer or related party had entered into a binding contract for the construction thereof on or before April 11, 2005, or in the case of self-constructed property, has started construction on or before April 11, 2005.

  3. A natural gas gathering line is defined by IRC 168(i)(17) to include any pipe, equipment, and appurtenance that is:

    1. determined to be a gathering line by the Federal Energy Regulatory Commission, or

    2. used to deliver natural gas from the wellhead or a common point to the point at which such gas first reaches:

    • a gas processing plant,

    • an interconnection with an interstate transmission line,

    • an interconnection with an intrastate transmission line, and

    • a direct interconnection with a local distribution company, a gas storage facility, or an industrial consumer.

Intercompany Marine Transportation

  1. This section sets forth the circumstances under which the Service will accept the use of Third Party Crude Oil Tanker assessments as a measure of the cost of marine transportation incurred on crude oil between related parties.

Overview of Marine Transportation

  1. One of the major elements in the cost of foreign crude oil and products imported into the United States is the freight charge. Because foreign crude oil and products are typically purchased by U.S. importers f.o.b. the loading port, freight charges are determined separately and are paid by the importer to a related company engaged in the transportation of oil. Examiners should review these intercompany charges to determine if they meet the arm's length standard set by regulations under IRC 482.

  2. Average Freight Rate Assessment (AFRA) was one of the principal means used by the oil industry on a worldwide basis to determine intercompany freight charges. Starting in the 1990's many petroleum companies no longer owned crude oil tankers. Today, the ASBA Tanker Broker Panel, LLC provides the industry with independent and anonymous oil tanker rate asssessments.

  3. When a U.S. importer pays marine transportation charges directly to an independent shipper for crude oil and products imported into the U.S., such charges are ordinarily allowed as a cost element for the crude oil products.

Historical Use of AFRA (old method)
  1. AFRA rates were calculated monthly by the London Tanker Brokers' Panel. The rates were published as of the first day of each month ended on the 15th day of the previous month. AFRA was an average of all charters for vessels in service during a specified period, irrespective of the dates on which the charters were concluded. It included time charters and charters for consecutive voyages, both for long- and short-term periods, as well as single voyages (spot) charters. The charter rates were weighted according to the amount of cargo carried.

  2. AFRA rates were expressed in terms of Worldscale, which is widely used in the shipping industry to denominate charter rates between independent parties as well as for AFRA and other purposes. Worldscale published rates, computed in U.S. dollars per metric ton, are cited as "Worldscale 100" or W100.

    Example:

    An AFRA assessment of W60 indicates that the rate for any particular voyage is 60 percent of the Worldscale dollar rate for a chartered voyage.

  3. Worldscale rates are revised annually

  4. Under Delegation Order No. 153, rescinded December 1, 2011, the Director Natural Resources and Construction, was assigned the nationwide authority and jurisdiction to determine the acceptance of AFRA or other freight rate determination methods as an intercompany charge for shipping of foreign-produced crude oil and products.

Tanker Broker Panels (new method)
  1. The ASBA Tanker Broker Panel, LLC (ASBA) is a limited liability corporation comprised of six well-established United States tanker brokerage companies. The IRS has evaluated and monitored ASBA tanker rates on a continuing basis. ASBA is supported by oil companies, oil traders, shipping companies and others.

  2. A company importing crude oil may adopt the use of Tanker Rate assessments provided by the ASBA Tanker Broker Panel to compute its intercompany and intracompany marine freight charges. Other Tanker Rate Assessments may be developed and those will be evaluated on a case-by-case basis by examiners.

  3. Companies must supply the documentation used to obtain the rates from ASBA to the IRS for each verification.

Transshipment
  1. Transshipping charges are those incurred in transferring cargo from one ship directly to another ship or to an on-shore terminal for later loading on another ship. The cost of transshipping is a proper charge to the importer.

  2. Transshipping has become significant with the shipment of Persian Gulf and African crude oils to terminals in the Caribbean for later shipment to U.S. ports. The U.S. importer will be charged transportation fees for the two legs of this journey plus a transshipping fee paid to the terminal owner. When transshipping occurs at sea or outside a port listed in the Worldscale service, the U.S. importer will ordinarily request the associations preparing Worldscale to compute special freight rates to the point of transshipment.

  3. When the transshipping fees are paid to affiliated companies, such charges should be made at arm's-length standards, taking into account the cost of transferring oil between ships or between ships and terminals and the period of storage, if any. Examiners should analyze such intercompany fees.

Intransit Pipeline Costs
  1. Intransit pipeline costs are those incurred in transferring cargo from one ship via pipeline to another, e.g., transferring cargo from a Red Sea port to a Mediterranean seaport via the Sumed pipeline. Pipeline related tariff and other transfer expenses are proper charges to the importer. As with transshipping costs, when intransit pipeline costs are paid to affiliates, they should be at arm's-length.

Lightering
  1. Lightering is a charge of unloading a part of a cargo into barges or other small ships to enable the tanker to be berthed in a port which is not large enough to accommodate the tanker when fully loaded. The term lightering has also been used to describe the complete off-loading of a vessel. This has generally been considered transshipping. In either event the cost of lightering is a proper charge to the U.S. importer. When the lightering charge is paid to an affiliate, the charge is subject to the arm's-length standard.

Deadfreight

  1. Deadfreight is the excess cargo capacity on a partially loaded tanker, e.g., a 90,000 dwt ship with a cargo of 60,000 tons of cargo, stores, bunkers, etc., would have 30,000 tons of deadfreight. Tankers may be light loaded for the following reasons:

    1. To allow them to berth in ports which are not large enough to accommodate the tankers when fully loaded

    2. Non-availability of sufficient cargo at the loading port

    3. Lack of sufficient storage space at the discharging port

    4. Need to transit waterways with draft restrictions

  2. Deadfreight is not an allowable charge to the importer when it is incurred for the benefit or convenience of the shipping company.

Demurrage

  1. Demurrage is a charge paid to a vessel owner or operator when a vessel is delayed in port beyond the lay time allowed by contract. The allowed lay time varies with each contract, usually depending on the size and loading capacity of the vessel; however, allowed lay time of 72 hours is common. Demurrage may be allowed if, due to the fault of the seller or buyer of the cargo, loading or unloading is not completed within the allowed lay time.

  2. Worldscale volumes include standard tables giving demurrage rates for various size ships. These rates can be used in conjunction with the assessments to determine the amount of demurrage on a particular shipment.

    Example:

    The Worldscale volume gives the demurrage rate for a 90,000 dwt ship as $15,200 per day. If the assessment for the particular shipment is W60, the daily demurrage rate would be $15,200 x 60 percent or $9,120. This rate is equivalent to $380 per hour.

  3. Demurrage is an allowable charge to the importer to the extent the importer caused the delay that resulted in the demurrage charge.

    1. The importer is not responsible for vessel related delays such as vessel equipment malfunctions, fueling, late arrival or vessel operations. Storm delays may be shared by both parties.

    2. The importer is not normally responsible for delays at the loading facility. The title to the crude purchased on an FOB basis passes to the importer as the crude is loaded onto the vessel. Delays in the loading port may be paid by the importer and recovered later from the producer or seller.

    3. The importer may be responsible for the demurrage charge at the discharge port when the delay is caused by the importer's employees or facilities.

      Example:

      If the importer's offloading equipment, pipeline or storage facility malfunctioned, the delay would be its responsibility. If the offloading facilities belong to a third-party, they may be responsible for the delay. If the delay is caused by the vessel's equipment, the shipping company is responsible.

    4. Demurrage is incurred when the actual time for the voyage exceeds the contract time. If there is no specific identifiable cause for the delay it will be assumed to be related to the vessel and the shipping company will not be entitled to demurrage.

  4. Demurrage charges are applicable only to the normal delays incurred in loading and discharging cargo. When extended delays are incurred and the delays indicate the ship is being used for storage, the demurrage rate should be adjusted by the examiner to an amount commensurate with on-shore storage, if appropriate. Such adjustments must be made on a case-by-case basis. Delegation Order No. 153 which was previously applied, was rescinded December 1, 2011.

Other Charges

  1. Charges such as insurance, fees, and taxes not included in the Worldscale will be allowed to the U.S. importer or to the shipper in accordance with industry practice.

Leveraged Oil & Gas Drilling Partnerships

  1. The use of partnerships by investors in certain drilling operations to claim losses and current deductions for intangible drilling and developments costs (IDC) in amounts that the Service contends exceed both the partnerships' actual IDC and the investors' economic outlay is described below. While not all oil and gas drilling partnerships engage in these abusive transactions, it is an area that calls for a heightened awareness by agents examining these partnerships.

Introduction

  1. This section discusses abusive leveraged oil and gas drilling partnerships (LOGDP). Procedures are provided to assist examiners when identifying and handling a LOGDP case.

    Note:

    Many oil and gas partnerships are not engaged in abusive transactions

    . A leveraged oil and gas drilling partnership is abusive when it is formed by use of promissory notes to artificially inflate the partners' interests in the partnership and generate tax deductions far in excess of the actual economic loss.

  2. Because of the complex structure of LOGDP, use of a Technical Specialist is highly recommended.

Partnership Formation and Description

  1. The LOGDP are created by a promoter that forms a partnership or multiple partnerships through which investors participate in oil and gas drilling activities. The abuse occurs at the investor level and because this type of transaction is typically created as an enterprise group, is detectable only by auditing the entire group of entities.

  2. The oil and gas drilling activities are conducted through a contractual arrangement between the partnership and promoter-controlled entities. A promoter-controlled upper tier entity is responsible for acquiring working interests in oil and gas wells. A promoter-controlled middle tier entity known as a turnkey drilling company (TDC) is designated as the party responsible for providing subcontracted drilling services for the wells. The general structure of a leveraged oil and gas drilling partnership is graphed below.

Description of the LOGDP Transaction and Key Entities

  1. The LOGDP abusive transaction involves investors contributing cash and signing a promissory note to a partnership that is generally 2-4 times greater than the amount of cash contributed. The promissory note is typically a long term obligation to be paid at a future date, usually in 15-25 years. The partnership does not loan the investor any money when the note is signed. The transaction involving the Turnkey Contract artificially inflates the partners' interest in the partnership, also known as the partners' "outside basis" and may generate a tax deduction that is several times greater than the cash contributed by the investors.

  2. The partnership signs a Turnkey Contract with the promoter controlled TDC. The contract is the basis for the Intangible Drilling Cost (IDC) deduction. The contract price is close to the total cash and promissory notes contributed by the partners. The cash is immediately paid by the partnership to the TDC. Subsequently, the TDC pays the money to the promoter-controlled upper tier entity. The Turnkey Contract includes a turnkey promissory note for the remaining balance. The turnkey promissory note mirrors the promissory note the investor signs with the partnership. Thus, the partnership has an asset and liability for the same amount.

  3. The turnkey promissory note is effectively an obligation to make payments to the promoter-controlled TDC for future services; therefore, the payments will be deductible by the partnership as they are made. The turnkey promissory note does not increase the partnership’s basis in its assets nor does it give rise to an immediate deduction or an expense that is properly chargeable to capital. Under this analysis, the turnkey promissory note is not a liability of the Partnership for IRC § 752 purposes, and therefore investors cannot increase their interests in the partnership by their share of the obligation.

  4. The IDC deduction is facilitated by the Turnkey Contract, and the related promissory notes. Generally, 50 percent of the cash contributed by the investors and none of the note amounts are spent on drilling operations. The contracts and notes are tools that attempt to artificially create basis and tax deductions for which the investors are not otherwise entitled.

  5. For further discussion of partnerships, see IRM 4.41.1.8.6.

Promoter Entities
  1. Turnkey Drilling Company (TDC) In the transaction described in IRM 4.41.1.8.3 the TDC does not drill the wells or perform any services. The TDC is a cash basis taxpayer and does not recognize the note portion of the contract as income. The TDC functions to provide a layer between the promoter’s upper tier entity that actually contracts with third party operators and the partnership. This allows the note portion of the Turnkey Contract to avoid income recognition and taxation by the promoter.

  2. Managing Partner It is common for the managing partner or Tax Matters Partner (TMP) to be selected by the promoter. The promoter is typically the "de facto" managing partner who sets the amount of the investors’ cash contribution and defines terms of the turnkey promissory notes. In addition, the promoter selects all the well sites and determines the Turnkey Contract Price. The managing partner or TMP generally does not contribute cash and does not have any liabilities. Typically the managing partner has a 1 percent interest in profits and losses. The cash contribution for the managing partner is generally made in a subsequent year by one of the promoter’s companies. In some cases it is never made. Hence, the overall effect of the transactions is that the partnership will have an asset that is slightly greater than the related liability. Although the managing partner is authorized to perform many acts and duties by the partnership agreement he does not actually perform any duties and his only real function is to be a figurehead for the promoter.

  3. Subsequent Year Partnerships It is common for the promoter to create several partnerships in subsequent years with the same investors participating in a new partnership in each subsequent year. Examiners should request subsequent tax returns for inspections.

Basics of Identifying a LOGDP

  1. A typical LOGDP will have large IDC deductions on the tax return or on Schedule K1.

  2. In some cases the IDC may be included on the Cost of Goods Sold line or other expense lines on the return so examiners need to review the balance sheet.

  3. In addition to the large deduction, the balance sheet will report a large receivable and a substantially similar amount as a note payable or other liability. The receivable will compromise most of the assets. Likewise the related liability will comprise most or all of the total liabilities.

  4. In some cases IDC is a separately stated item on schedule K. In some cases IDC is reported in other deductions on page 1 of the 1065. It may not be called IDC. In all cases the IDC is the largest of the expenses deducted on the return.

  5. The following sections are designed as a planning tool to help in the pre-exam and field work portions when auditing LOGDP issues. It is imperative that the revenue agent and petroleum engineer collaborate during the course of the exam.

LOGDP Audit Steps

  1. Review Books and Records. Although the agent will have primary responsibility for examining the items below, the documentation revealed from the examination of the books and records will often be important to the other specialties working on the case and used in their audit work (for example, engineer or international agent). Integrating complementary skills and working together as a team has proven more effective in factual development rather than having each specialty work in isolation and then assembling a final product at the end.

  2. The following describes items helpful in the planning and conduct of the examination. Refer to Exhibits 4.41.1-32 through 4.41.1-40 for recommended IDR's to be issued in LOGDP cases. Additional items for request and review:

    1. Partnership Agreement, including all amendments
    2. Prospect Agreement
    3. Assumption Agreement
    4. Subscription Agreement
    5. Subscription Note
    6. Turnkey Drilling Note
    7. Turnkey Drilling Contract
    8. Investment proposal or prospectus
    9. Other agreements embodied in letters or memoranda
    10. Actual drilling contracts and related operating documents

  3. Orientation. Review Exhibit 4.41.1-44, Glossary of Oil and Gas Industry Terms for an overview of engineering terms. Determine if TEFRA or Non-TEFRA procedures apply; see IRM 4.31.2, Pass-through Entity Handbook.

  4. Risk Analysis.

    1. Attempt to identify promoter and return preparer through conducting a yK-1 analysis; see IRM 5.20.12.7

    2. Review the K-1 for the partners’ classification as a general or limited partner

    3. Assess the likelihood of material participation. Hint: consider the address of the partner and location of the partnership (i.e., is the partner in a non-oil state or high-tax state)?

    4. Identify all the partners in the partnership to prioritize interviews. See Exhibit 4.41.1-41.

    5. Consider ordering in status 45 the top five investors’ individual tax returns (based on percent ownership)

    6. Inspect the investor returns for other abusive tax transactions

    7. Determine if IDC is deducted on investors’ tax returns

    8. Prepare an investor matrix to assist in understanding relationships among investors. See Exhibit 4.41.1-41, Tax Shelter Partner Listing.

  5. Coordination. It is likely that other taxing authorities have the same entities under audit. Information sharing allows for a more efficient audit. The agent should work with the Manager and Territory Manager to coordinate with these other authorities. Communication with these agencies must be established through proper procedures.

  6. The following steps should be considered:

    1. Coordinate with other divisions (LB&I or SBSE) if the tax returns are not in your division

    2. Establish contact with Governmental Liaison Officer (Disclosure) to obtain information sharing agreements with other taxing authorities (State and Local) where examinations are ongoing

    3. Determine if any of the investors, promoter, or other participants are under criminal investigation or investigation by other agencies and tax jurisdictions (i.e., state, city). Transaction Code 914 on AIMS database means active Criminal Investigation.

Partnership Audit Steps

  1. Partnership Formation

    1. determine who formed the partnership

    2. determine how the partnership was formed and what was contributed to the partnership in exchange for an interest in the partnership

    3. determine whether the investors received an investment prospectus or private placement memorandum

  2. See Exhibits 4.41.1-32 through 1-40 for additional items to request and review.

  3. Examine Books and Records

    1. Conduct a functional analysis of the partnership by reviewing actual business operations

    2. Determine if partnership activity reflects that an actual business is being conducted. For example, did the partnership invest in wells that were actually drilled?

    3. Determine if books and records are prepared by partnership, promoter, or third party

    4. Determine if drilling records are maintained by well or vendor

    5. Summons should be considered if information is not being received in a timely manner

  4. Review Cash Activity

    1. Follow the cash (review checks and deposits) to determine where money was spent. This will identify the actual activity of the partnership and may identify other entities to be audited.

    2. Look for payments to the promoter or promoter-controlled entities, and payments to related entities.

    3. Look for payment of personal expenses and non business expenses.

    4. Determine source of investor capital contribution (e.g. was it their cash or was it borrowed). If cash was borrowed from a party related to promoter, investor may not be at risk.

    5. Compare the actual expenses of the partnership to what is included on tax return and the Schedule K1's.

  5. Interview Questions. Interview the investors and return preparer after review of books and records. Suggested questions are:

    1. What does the investor know?
    2. What is the investor's background?
    3. How did the investor find out about the partnership?
    • who did the investor talk to?

    • what was discussed?

    • what documents did the investor receive?

    4. What information is received from the promoter?
    5. When did the investor become a partner?
    6. Is there any interaction with other partners?
    7. Are there non-tax reasons for investing?
    8. What are the financial benefits?
    9. Was anyone compensated?
    10. Does investor have basis?
    11. Is investor at risk for notes?
    12. How are notes paid back?
    13. What is the extent of the investor's liability for partnership debt?
    14. Has the investor made any payments on the debt?
    15. Does the investor list the loans on personal financial statements or loan applications?
    16. How does the investor intend to pay back the loan?
    17. Gain understanding of transactions.
    18. Does transaction occur as it is set up on paper?
    19. Are the wells actually drilled?
    20. Who determines which wells to drill?
    21. Does the partnership have a working interest in the wells?
    22. Does the transaction have economic reality?
    23. Is there a basis for assertion of penalties?
    24. What due diligence was done?
    25. Can the investor sell his partnership interest?
    26. Does the investor participate in management?
    27. Can the investor terminate the partnership?
    28. If the partnership is terminated, what partnership liabilities did the investor satisfy?
    29. Is this an abusive transaction?
    30. Is investor involved in similar transactions?

  6. Questions should be tailored to gain a full understanding of the promotion, the persons involved in the promotion and the investor's motives for participating in the promotion. Ideally, the interviews should be conducted face-to-face, but if time or money constraints limit this, prioritize interviews and/or conduct by written questionnaire.

    Note:

    Investors are considered third-party contacts. Refer to IRM 4.11.57, Examining Officer's Guide, Third Party Contacts.

  7. Notes and Other Documentation. Should the examination of the partnership notes reveal alleged debt, the examiner and engineer need to share information. Much of the RA's findings will impact the engineer's work. These debt instruments may have an accounting impact (e.g., how the notes were recorded) as well as a technical impact (e.g., how notes were used to inflate alleged drilling costs). The examination of the notes should determine:

    • if the loans are recourse or non-recourse

    • how the notes are repaid

    • if the notes are to a related party

    • if the loans are from the promoter or promoter-controlled entities

    • if there is a valid business purpose to the debt (e.g., does the loan leverage the tax deduction)

    • how the loans are actually repaid. Consider at-risk establishment factors.

    • how much (if any) of an investor's money was used to repay the debt

    • if the repayment plan and period are realistic

    • any prior loans that are outstanding by the partners to determine a history of repayments

    • the validity of any receivables (e.g., subscription notes)

    • if the partners can deduct any loss per IRC 704 by requesting a partnership basis schedule

  8. Consider at-risk limitations and passive activity loss rules. Refer to IRC 465,Deductions Limited to Amounts At Risk, and IRC 469, Passive Activities Losses and Credits.

Engineer Issues and Responsibilities

  1. An engineer may be called upon as an expert or summary witness regarding oil and gas industry practices and customary deal structures. The engineer’s report is a key product. The engineer will perform a functional analysis of the business activities and processes of the partnerships and turnkey drilling companies. The examination will primarily focus on how much money was spent for the actual drilling of any associated oil and gas prospect, and on collecting factual documentation to determine some of the following:

    • the business operations and drilling activity performed

    • whether the promoter owns or controls the Turnkey Drilling Company

    • whether the promoter formed or controls the partnership

    • what business function and actual business activity the Turnkey Driller performs

    • whether the partnership is entitled to the amount of Intangible Drilling Cost claimed on the return

    • the extent and dates of drilling activity actually performed, if any

    • who or what entity actually performed the drilling activity

    • the reasonableness of the turnkey drilling arrangement

  2. Consider hiring an outside expert to assist in determining:

    • whether the turnkey price paid by the partnership was reasonable and constituted an arms length transaction

    • whether the terms of the drilling contract were reasonable, customary and within industry standards

    • whether promoter-controlled drilling company or the partnership actually undertook the economic risk of drilling wells

  3. To address the above, consider as part of the factual development process whether the term Turnkey Driller and Turnkey Drilling Contract refer to the promoter-controlled entity typically styled as a "Turnkey Drilling Company" and the drilling contract between the partnership and that promoter-controlled entity.

    Note:

    A distinction is made between an actual unrelated third party turnkey drilling company in industry and a non-functioning promoter-controlled entity styled as a "Turnkey Drilling Company" that does not perform or contract for the actual drilling.

Taxpayer Audit Steps

  1. The following are recommended audit steps.

    1. Identify the operator of all drilling prospects associated with the partnership.

    2. Determine if the partnership has a working interest.

    3. Identify if there are any wells or activity outside of the United States.

    4. Refer to IRM 4.41.1.2.4.7.3 for Turnkey Contract issues.

    5. Compare wells actually drilled to wells listed in the document that transfers working interest often identified as a prospect agreement. Note any differences and whether any discrepancy is material to the factual development.

    6. Determine when the wells were actually drilled and whether any invoices were dated prior to the stated or actual formation of the partnership.

    7. Review the dates of the invoices for the wells and note any unusual lengths of time after the well was spudded (e.g., years after the well was drilled).

    8. Determine whether documents from third parties indicate the promoter, a promoter-controlled entity or its contractor, was the primary or sole contact with the actual well operators.

    9. Determine whether the division order or joint interest billing statements were sent to promoter or a promoter-controlled entity, as the named working interest partner for payment.

    10. Determine whether the promoter, promoter-controlled entity or the partnership signed the election letters for well operations.

    11. For each associated partnership, request executed copies of agreements between the Turnkey Driller and any well servicing companies for activities such as well logging, cementing, casing, perforating, fracturing and maintenance.

Promoter Audit Steps

  1. Promoter Substance Over Form Issues This section is to be worked jointly by the engineer and agent. Read the documents identifying debt and compare form of transaction to what actually transpired.

  2. Turnkey Drilling Activity

    1. For each associated partnership, verify whether the promoter-controlled Turnkey Driller actually engaged in drilling oil and gas wells with its own equipment and personnel or arranged for others to perform such tasks through written contract.

    2. For each associated partnership, request executed agreements between the Turnkey Driller (or any other promoter-controlled entity) and any third party drilling company contracted to drill wells for the Turnkey Driller. Determine whether the Turnkey Driller arranged for any wells to be drilled for promoter or a promoter-controlled entity. For each associated partnership, request executed agreements between the Turnkey Driller and any promoter-controlled entities contracted to drill wells for the Turnkey Driller. Note whether the taxpayer or promoter allege the contracts are verbal and no written contracts exist.

    3. Use Turnkey Driller Business Characteristics below to determine if the drilling company was actively engaged in the drilling business. Note whether the Turnkey Contract is alleged to provide extraordinary protection against unforeseen financial expenses.

      Turnkey Driller Business Characteristics
      Personnel knowledgeable in oil and gas drilling operations
      Equipment or other assets to drill oil and gas wells
      Written contracts with entities to perform actual drilling operations or well services
      Written contracts with entities to arrange for the drilling of oil and gas wells

    4. Perform a comparison of the terms of the promoter-controlled company's Turnkey Contract with those that would typically be included in a Turnkey Contract used in the industry. Note the differences between the promoter-controlled company's Turnkey Contract and the model form Turnkey Contract developed by the International Association of Drilling Contractors.

  3. Promoter Involvement

    1. Determine whether the promoter was an investor in the partnership. If a contract is between related parties (e.g., promoter-controlled partnership and promoter-controlled Turnkey Driller), are the price, terms, and structure of the contract arms length?

    2. Determine whether the promoter selected the tax matters partner or influenced the management of the partnership by the tax matters partner.

    3. Determine whether the promoter controlled the oil and gas income from any producing wells and used such revenue to pay ongoing drilling and operating costs, with any residual being applied to "interest" due on the notes from the investors.

    4. Identify who determined the turnkey price to charge the partnership. If it was the promoter, determine whether that person had the experience, training or expertise to develop a reasonable price that is credibly associated with the types of risk associated with drilling operations in the oil and gas industry.

  4. Promissory Notes

    1. Determine whether the investors' promissory notes were used as collateral for payment of a portion of the monetary amount required to drill the wells subject to the partnership agreement.

    2. Determine whether a turnkey promissory note (between the partnership and the Turnkey Driller) was secured by the investor promissory note (Subscription Note between the partnership and the investor).

    3. Determine whether the promissory notes were used as a means to inflate the IDC claimed on the return. Compare the amount of IDC actually incurred to the amount claimed on the return and based on the drilling contract price set by the promoter or promoter-controlled Turnkey Driller (view third-party invoices).

    4. Determine whether the notes are recourse or non-recourse in nature. Is there language in any side agreements that limit the investor's ability or debt repayment requirement?

    5. Is the note to be paid out of future oil and gas revenue in whole or in part?

    6. Does the partnership pledge its assets to secure the note?

Penalty Considerations

  1. The LOGDP is an abusive transaction and penalties such as negligence and valuation misstatement apply.

  2. Refer to IRM 4.20.1, Examination Collectibility and IRM 4.10.6, Examination of Returns, Penalty Considerations for guidance.

  3. The agent determines if the transaction is tax motivated:

    • Were new investor dollars used to fund prior investments? (Note whether there are elements of a Ponzi scheme.)

    • Review transactions for economic reality

    • Would the investment be reasonable without the tax benefits?

    • Would a reasonable investor invest in this promotion without the tax write-offs?

    • Determine the amount of due diligence by each investor

    • Determine if the investor consulted with an independent third party

Preparer/Promoter Considerations

  1. Consider whether a preparer penalty (IRC 6694) or a promoter examination (IRC 6700) is warranted.

  2. Consult with a manager or technical specialist to determine if action should be initiated.

Activities and Personal Services Provided on the U.S. Outer Continental Shelf

  1. In General

    1. The U.S. Outer Continental Shelf (OCS) is the continental shelf adjacent to U.S. territorial waters over which the United States has the exclusive right of exploring for and exploiting natural resources.

    2. Vessel owners (including vessel charterers in the chain between the vessel owner and the operator) and vessel operators may be engaged in activities related to the exploration for, or exploitation of, natural resources on the OCS. These activities include, for example, seismographic testing, drilling services, repair and salvage work, and the transportation of supplies and personnel between U.S. ports and the OCS.

    3. These services generally are carried out by contractors using vessels that are designed and/or modified for a specialized purpose, such as seismographic testing. The contractor may own the vessel, but often leases it from a third party. Depending on their function, the vessels may either stay in the same location for long periods of time or regularly move from location to location. Vessels may be foreign-flagged, and vessel owners and/or operators may be foreign individuals or companies.

  2. IRC 638 and Associated Treasury Regulations

    1. For purposes of applying Chapter 1 of the Code (which includes rules for sourcing income) with respect to mines, oil and gas wells, and other natural deposits, IRC 638 applies the term "United States" as a geographical reference to include the Outer Continental Shelf.

    2. Under Treas. Reg. 1.638-1(c)(1), persons, property, or activities that are engaged in or related to the exploration for, or exploitation of, mines, oil and gas wells, or other natural deposits (collectively known as IRC 638 activities) don't need to be physically on, or connected or attached to, the seabed or subsoil of the OCS to be deemed within the United States.

    3. Treas. Reg. 1.638-1(c)(4) clarifies that persons, property, or activities are within the United States only to the extent they are engaged in Section 638 activities.

    4. Section 638 activities are not limited to exploration and exploitation. Activities must merely be related to the exploration for or exploitation of natural resources in the OCS to be section 638 activities.

      Note:

      In PLR 200823005, foreign-owned and leased vessels were engaged in the removal and repair of underwater oil and natural gas pipelines; the inspection, maintenance, and repair of production platforms and wellheads; and the salvage of pipelines and production related equipment. The Ruling concluded that " Although the services do not constitute the actual drilling of oil and gas wells, such repair and remediation of oil and gas infrastructure are clearly related to the exploitation of natural resources, and fall within the ambit of Section 638."

    5. Treas. Reg. 1.638-1(d)(1) defines natural deposits and natural resources as nonliving resources to which Section 611(a) applies (e.g., the depletion deduction). Natural deposits and natural resources do not include sedentary species, fish, or other animal or plant life.

  3. Tax Consequences of the OCS being in the United States

    1. IRC 638 activities may give rise to U.S. source income.

    2. Accordingly, a foreign corporation that derives income from section 638 activities may be taxable in the United States. If the foreign corporation is engaged in a U.S. trade or business and the income is effectively connected with that U.S. trade or business, tax is imposed on that income at graduated rates on a net basis under IRC 882(a).

    3. If the foreign corporation is not engaged in a U.S. trade or business, tax is generally withheld on U.S. source income on a gross basis at a 30 percent rate under sections 881(a), 1441, and 1442.

    4. If the foreign corporation is a resident of a country with which the United States has a bilateral tax treaty, it may be exempt from withholding, or eligible for a reduced rate of withholding.

    5. A foreign corporation that is claiming a reduced rate of withholding tax or an exemption from withholding tax must file a W-8BEN with the withholding agent, generally the payor. See regulations under IRC sections 883, 1441, and 6114, and consider contacting an International Technical Specialist or an International Examiner.

    6. A vessel engaged in section 638 activities is generally not deriving income from the international operation of a ship, which is often exempt from tax under a treaty or section 883. Examiners should ensure that income characterized as from international transportation activities is not in fact from section 638 activities.

    7. If a foreign entity operating in the OCS is claiming it is exempt from U.S. tax, Examiners should verify the foreign entity's activities and the legal basis for its claim. This might include, for example, reviewing contracts and the types of vessels being used by the foreign entity.

    8. The following U.S. reporting may be required in connection with section 638 activity:

    • Form 1120-F (U.S. Income Tax Return of a Foreign Corporation) for foreign corporations engaged in a U.S. trade or business.

    • Form 1042 (Annual Withholding Tax Return for U.S. Source Income of Foreign Persons) filed by withholding agents that withholding tax on U.S. source payments to foreign corporations not engaged in a U.S. trade or business.

    • Form 8833 (Treaty-Based Return Position Disclosure Under section 6114 or 7701(b)) (for foreign corporations claiming an exemption from, or reduced rate of, tax under the provisions of a treaty)

    • Form 941 (Employer's Quarterly Federal Tax Return) (for foreign corporations conducting section 638 activities that are required to withhold employment taxes from remuneration to employees).

  4. Withholding

    1. As discussed above in Tax Consequences of the OCS being in the United States, payments to foreign companies for section 638 activities are generally subject to withholding tax under IRC sections 1441 and 1442.

    2. A withholding agent is defined in Treas. Reg. 1.1441-7(a)(1) as any person, U.S. or foreign, that has the control, receipt, custody, disposal, or payment of an item of income of a foreign person subject to withholding. A withholding agent may be an exploration and production company, a project manager, or a contractor.

    3. Residence is not relevant to determining whether a person is a withholding agent. Foreign and U.S. persons can be withholding agents.

    4. A foreign company claiming an exemption from withholding under a treaty must file a Form W-8BEN (Beneficial Owner's Certificate of Foreign Status for United States Tax Withholding) with the withholding agent.

    5. An Examiner should review all Forms W-8BEN provided to withholding agents. If the treaty benefit being claimed by the foreign companies is not consistent with the facts (for example, a foreign company with modified and specialized vessels that claims to be engaged in international transportation), the examiner should consider whether the withholding agent should have filed a withholding tax return (Form 1042), and is liable for failing to withhold tax.

  5. Treaty Claims

    1. Treaty claims must be examined closely because U.S. bilateral treaties vary from country to country and some treaties (e.g., Norway) have special provisions with respect to Section 638 activities.

    2. In particular, there is a wide variation among treaties over how of the terms permanent establishment and business profits are defined.

    3. To be eligible for a treaty benefit, a foreign corporation must be a resident of the foreign county with which the United States has a treaty; qualify under the Limitation on Benefits article in the treaty; and meet any additional requirements under the treaty article for which it is claiming the benefit.

    4. Special attention must be given to a foreign entity's claim that it is exempt from tax under a treaty because it does not have a permanent establishment. A mine, oil or gas well, quarry, or any other site where natural resources are being extracted will give rise to a permanent establishment if the activity is continuous and of a certain duration. The duration may range from 90 days (e.g., the U.S.-Canada treaty) to 12 months. Special treaty provisions apply to income that is attributable to a permanent establishment.

    5. A foreign company claiming an exemption from, or reduced rate of, U.S. tax under an income tax treaty generally must attach a Form 8833 (Treaty-Based Return Position Disclosure under section 6114 or 7701(b)) to its Form 1120-F setting forth:

    1. the treaty position and article it is relying upon for the exemption from or reduced rate of tax;

    2. its country of residence; and

    3. an estimate of the gross income that is exempt from tax.

    Failure to disclose a treaty-based return position may result in penalties under section 6712.

  6. Field Directives

    1. Industry Directors Directive # 1 - United States Outer Continental Shelf Activity, published October 28, 2009. See Industry Director’s Directive #1 - United States Outer Continental Shelf Activity.

    2. Industry Directors Directive # 2 - Employment Tax and the Employees on the U.S. Outer Continental Shelf, published March 30, 2011. See Industry Director’s Directive # 2—Employment Tax and the Employees on the U.S. Outer Continental Shelf.

Research Material Available, Oil and Gas Taxation

A. Oil and Gas Taxes, Prentice Hall, Inc.
B. The RPI Primer of Oil Exploration, Drilling and Production, Resource Programs, Inc.
C. A Primer of Oilwell Drilling, PETEX, The University of Texas at Austin
D. Bulletins published by the Council of Petroleum Accountants Societies of North America (COPAS)
E. Primer of Oil and Gas Production, American Petroleum Institute
F. Oil and Gas Quarterly, Matthew Bender & Co., Inc.
G. Oil and Gas Journal (published weekly), PennWell Publishing Co.
H. Manual of Oil and Gas Terms, 14th Edition, Williams and Meyers

Division of the Production From Oil and Gas Property

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Useful Examination Techniques — Lease Acquisition Costs

1. Scan the non-producing lease account in the asset section of the ledger to determine the number of oil and gas leases acquired during the year and their names.
2. Test lease operating costs, legal and accounting, office supplies, miscellaneous, and similar accounts for acquisition costs that may have been deducted as current expenses.
3. Inquire about the taxpayer's method of allocating overhead costs to the leases acquired. Are land department costs, salaries of geological departments, and administrative costs included in the cost of properties acquired? Request copies of authorization for expenditures (AFE) for lease purchases to see if direct costs are set out as part of the cost of the property.
4. Test the delay rental account for bonuses that may have been charged to expense in error.
5. Has the taxpayer allocated leasehold cost correctly on producing leases purchased? Do you need engineering assistance?
6. Scan and test the chargeoffs of geological and geophysical expenses to determine if they should be capitalized as cost of drilling projects acquired.
a. Were seismic costs incurred in areas where leases were acquired?
b. Have commissions to geologists or consultants been incorrectly deducted as IDC?
c. Have seismic survey projects really been abandoned without acquiring leases? Scan subsequent year acquisitions. (Some lessors, such as state or Federal government, put selected lands up for lease each year and hold other lands to put up for future years.)
d. Questionable deductions should be brought to the attention of an IRS petroleum engineer.
e. See Rev. Rul. 77–188, 1977–1 CB 76 and Rev. Rul. 83–105, 1983–2 CB 51.

Useful Examination Techniques — Intangible Drilling and Development Costs

1. Determine if the taxpayer has made a proper election to deduct IDC as a current expense.
2. Test the larger deductions in the intangible development expense account.
a. Schedule large amounts
b. Request invoices
c. Request AFEs
d. Compare above documents with amounts claimed
3. Inspect the drilling contracts on a selected basis, especially December deductions.
4. Determine if prepaid IDC is required by the contract, or if it is merely a deposit, and whether or not paid directly to the drilling contractor.
a. Determine when the well was "staked" and when work was started.
b. Consider the facts surrounding the prepaid IDC in relationship to Rev. Rul. 71–579, 1971–2 CB 225, and 71–252, 1971–1 CB 146.
c. Consider the effect of an adjustment. Does the adjustment have tax significance or would it be a mere "rollover?" (remember timing of IDC deduction could affect the net income limit for percentage depletion under IRC 613A).
5. Scan the depletion schedules to determine which newly acquired leases are productive.
a. Have the drilling costs been shown as a deduction on the leases for the 100-percent percentage depletion limitation?
b. Prepare a list of new productive leases from the depletion schedule.
6. From the list prepared in item 5(b), request the lease files on all new productive leases, or on a selective basis if the number is large.
a. Review the lease files to determine if the taxpayer's ownership percentage corresponds with the amount of IDC deducted. If not, why? Is the deduction allowable?
b. Review assignments, correspondence, and related documents to determine if the taxpayer has drilled for his/her interest in the lease and if he/she is "carrying" other owners.
c. If transactions as described in (a) and (b) are found, has the taxpayer handled them correctly? See Rev. Rul. 70–657, 1970–2 CB 70; Rev. Rul. 71–206, 1971.1 CB 105; Rev. Rul. 69–322, 1969–1 CB 87; Rev. Rul. 77–1 76, 1977–1 CB 77, etc.
7. Scan the producing lease account in the asset section of the ledger.
a. Note the leases that have been removed (credits).
b. Have the leases removed been reported as sales?
c. Should IDC be recaptured in accordance with IRC 1254?
8. Allocate a reasonable amount of administrative overhead costs to IDC for tax preference purposes before computing the minimum tax.
a. Usually, this can be done by allocating overhead based upon the direct departmental costs.
b. In many cases, this can be easily accomplished by using the taxpayer's workpapers prepared for the purpose of allocating overhead for depletion purposes.
9. Taxpayers must own the entire working interest during the complete payout period to be allowed to deduct 100 percent of the IDC in a carried interest arrangement.
10. Has surface casing been deducted?
11. Has IDC been shown in operating expenses incorrectly to avoid minimum tax under IRC 57 or recapture under IRC 1254?

Classification of Expenditures in Acquisition, Development, and Operation of Oil and Gas Leases

A. Leasehold Cost (Capital Expenditure)
1. Research of lease location by engineer, geologist, etc., for purposes other than locating a well site.
2. Geological and geophysical expenditure leading to acquisition or retention of an oil and gas property (limited to expenditures after August 8, 2005 for foreign properties; see IRM 4.41.1.2.2.3.1).
3. Expenses in connection with leasing the property from a landowner.
4. Legal costs of securing lease and clearing title.
5. Legal fees incurred to obtain access to the property and to obtain easements, etc.
6. Lease bonus paid to the landowner or other owner.
7. Purchase price of an existing lease.
8. Core-hole wells drilled to obtain geological data (limited to expenditures after August 8, 2005 for foreign properties; see IRM 4.41.1.2.2.3.1).
9. Cost of seismic work incurred by an oil and gas company to determine the size of the reservoir or reserves (limited to expenditures after August 8, 2005 for foreign properties; see IRM 4.41.1.2.2.3.1).
10. Legal fees incurred in drafting contracts.
11. Travel expenses incurred in acquiring leases.
12. Salaries of land department personnel in acquiring leases.
13. Equalization payments paid in furtherance of a unitization when paid in connection with prior IDC.
14. Bottom-hole contribution when paid to obtain information which enhances the value of the property (limited to expenditures after August 8, 2005 for foreign properties; see IRM 4.41.1.2.2.3.1).
15. IDC if no election to expense has been made under IRC 263(c) or if "foreign IDC."
16. Delay rentals unless the taxpayer can establish that it was not reasonably likely for the lease to be developed.
17. Remaining basis in equipment which is transferred to another person under any type of reversionary agreement.
B. Intangible Drilling Costs (current deductions or capital cost depending on election)
1. Administrative costs in connection with drilling contracts.
2. Survey and seismic costs to locate a well site on leased property.
3. Costs of drilling.
4. Grading, digging mud pits, and other dirt work to prepare drill site.
5. Cost of constructing roads or canals to drill site.
6. Surface damage payments to landowner.
7. Crop damage payments.
8. Costs of setting rig on drill site.
9. Transportation costs of moving rig.
10. Technical services of geologist, engineer, and others engaged in drilling the well.
11. Drilling mud, fluids, and other supplies consumed in drilling the well.
12. Transportation of drill pipe and casing.
13. Cementing of casing (but not the casing itself).
14. Rent of special equipment and tanks to be used in drilling a well.
15. Perforating the well casing.
16. Logging costs, but not velocity surveys.
17. Costs of removing the rig from the location.
18. Dirt work in cleaning up the drill site.
19. Cost of acidizing, fracturing the formation, and other completion costs.
20. Swabbing costs to complete the well.
21. Cost of obtaining an operating agreement for drilling operations.
22. Cost of plugging the well if it is dry.
23. Cost of drill stem tests.
C. Lease and Well Equipment (Capital Expenditures)
1. Surface casing.
2. Equalization payments of a unitization when paid in connection with equipment.
3. Cost of well casing.
4. Salt water disposal equipment and well.
5. Transportation of tubing to supply yard but not from supply yard to well site.
6. Cost of production tubing.
7. Cost of well head and "Christmas Tree."
8. Cost of pumps and motors including transportation.
9. Cost of tanks, flow lines, treaters, separators, etc., including transportation.
10. Dirt work for tanks and production equipment.
11. Roads constructed for operation of the production phase.
12. Laying pipelines, including dirt work and easements.
13. Installation costs of tanks and production equipment.
14. Construction costs of trucks turnaround pad and overflow pits at new tank battery.
D. Lease Operating Expense (current deduction)
1. Cost of switcher or pumper to operate the wells.
2. Cost of minor repair of pumps, tanks, etc.
3. Grading existing roads.
4. Treat-o-lite and other materials and supplies consumed in operating the lease.
5. Pulling sucker rods, pump, and cleaning the well.
6. Utilities.
7. Taxes other than Federal income taxes.
8. Depreciation of equipment used on the lease.
9. Rental of lease equipment.
10. Salaries for painting and cleaning the lease.
11. Lease signs.
12. Salaries of other operating personnel—farm boss, superintendent, engineer, etc.
13. IDC when elected to expense under IRC 263(c).
14. Salt water disposal costs (other than those under C.4. above).
15. Allocable portion of overhead costs.
16. Qualified tertiary injectant expenses. See Treas. Reg. 1.193–1 and IRM 4.41.1.3.3.6.

Rules Regarding Foreign Geological and Geophysical Expenditures

When foreign geological and geophysical expenditures are encountered, such expenditures must be capitalized. The tax treatment of foreign G&G exploration expenditures is discussed in Rev. Rul. 77-188, 19771-1 C.B. 76 as amplified by Rev. Rul. 83-105, 1983-2 C.B. 51. These rulings set forth an exploration program is conducted in stages with specific identification of a project area, area of interest, and the acquisition of properties.

  1. First, the project area associated with the subject expenditures must be identified. The agent should request copies of the AFEs with respect to expenditures expensed. Generally, taxpayers will incur expenditures regarding reconnaissance type surveys; these are the original or first surveys conducted over a project area. Typically, no specific property (i.e. leasehold) has been acquired at this stage of the project; such reconnaissance type survey costs are held in a suspense account until such time the expenditure may be capitalized to a particular property or an event occurred that enabled the taxpayer to write off such expense.

  2. Second, as a result of the reconnaissance type survey, the taxpayer will identify specific geological features that may be conducive for hydrocarbons. Such geological features are defined as an area of interest within the project area. The reconnaissance type survey costs are allocated equally to each area of interest regardless of size or relative costs. The examiner must be aware that taxpayers usually designate many areas of interest so that a large portion of the geological and geophysical costs are capitalized to areas of interest which are abandoned.

  3. Lastly, within each particular area of interest have specific properties been acquired. If so, the capitalized geological and geophysical expenditures associated with the area of interest (held in suspense account up to this stage) are allocated to each property acquired based on acreage.

If an entire area of interest proves unfavorable for development (if no lease is obtained), the allocated exploration costs (reconnaissance and detailed costs) are deductible as a loss in the year the area is abandoned. Refer to Treas. Reg. 1.614-6(d). Rev. Rul. 83-105 establishes an identifiable event is a prerequisite for a loss deduction, a decision not to pursue a particular area of interest is not sufficient. Examples of an identifiable event that would trigger a loss deduction include:

  • a lease sale occurs and the taxpayer is unsuccessful in acquiring

  • data obtained indicates the absence of mineral producing potential

If only a portion of an area of interest proves worthless, a loss cannot be deducted until the complete area of interest is abandoned as a potential source of mineral production. The taxpayer’s lease record and the taxpayer’s current land map should disclose if the taxpayer holds any leases within the project area.

Example:

The OilCoA, as a result of a preliminary survey work, obtains an option or selective type lease covering 10,000 acres at a cost of $4 per acre, or $40,000. The lease is for a term of 5 years and 6 months. The terms of the lease provide that a minimum of 25 percent of the acreage must be selected before the expiration of 6 months, a bonus of $10,000 per acre must be paid on the selected acreage, and a delay rental of $2.00 per acre per annum be paid on acreage selected. The preliminary survey, core drilling, and other geological and geophysical costs amounted to $24,000. Prior to the expiration of the first 6-month period, OilCoA selected 2,500 acres under the lease which they paid $25,000 bonus. The $40,000 option cost, the $24,000 geological and geophysical expenditures, and the $25,000 bonus should be capitalized as leasehold costs of the 2,500 acres of land selected. The taxpayer may claim an abandonment of 7,500 acres and a loss of 75 percent of the $40,000 option cost plus all or part of the $24,000 geological and geophysical costs paid. This abandonment will appear as a credit to the leasehold account and a debit in the Expired and Surrendered Leases Expense. The leasehold account may explain this credit as "release acreage" when actually the company never had a lease on the acreage, but only an option. The lease record usually identifies a lease by its terms, bonus, acreage, and other provisions, thereby making possible the identification of each lease acquired.


Note:

Remember that all

of the geological and geophysical expenditures incurred in an area of interest are allocated to the acreage acquired and retained in the area. The acreage not retained is outside of the area considered to be favorable for development, regardless of the fact that an option was obtained as a protective measure during the study. See Rev. Rul. 77-188, 1977-1 C.B. 76 and Treas. Reg. 1.234.2. For further explanation of Rev. Rul. 77-188 and detailed examples of the tax treatment of foreign geological and geophysical costs, see Rev. Rul. 83-105, 1983-2 C.B. 51.

Information Required Before Maximum Allowable Depletion Can be Computed

What is the taxpayer's average daily production of domestic crude oil and how was it computed [IRC 613A(c)(2)]?

Is the taxpayer required to share the tentative depletable oil quantity with related entities or family members [see IRC sections 613A(c)(3) and (8)]?

If question 2 is "yes" , determine the taxpayer's individual share of tentative oil quantity under IRC sections 613A(c)(3) and (8).

Is the percentage depletion limited to 65 percent of adjusted taxable income?

Are any of the properties marginal oil or gas production properties held by independent producers or royalty owners

Have overhead expenses been allocated to the properties for percentage depletion purposes?

Is the taxpayer a refiner or retailer [IRC 613A(d)(2) or (4)]?

  1. Note:

    The information above is not needed for a taxpayer with only a few small oil and gas leases because the facts may be obvious. However, for a taxpayer with large production, much time can be saved by obtaining the facts above before making any computations.

Steps in the Computation of Depletion for All Taxpayers Other than Retailers or Refiners as Defined in IRC sections 613A(d)(2) & (4)

Steps:

  1. Start with a schedule of all properties in which the taxpayer owns an economic interest and has income from production of oil or gas. If the taxpayer is on a tax year different than a calendar year, for computation of percentage depletion under IRC 613A(c), treat each part of a calendar year within the tax year as if it were a "short period" return. Two separate percentage depletion computation schedules are required for a fiscal-year taxpayer. For each property, the allowable percentage depletion deductions from each schedule are combined to compute the property's allowable percentage depletion deduction for the fiscal year. Each property's allowable percentage depletion deduction is then compared with that property's cost depletion deduction. The larger of the two computed deductions is the allowable deduction. The agent should scan the schedule for leases with similar names and consider the effect on the computations if properties with similar names were, in fact, one property as defined in IRC 614. The agent should obtain the lease acquisition and well files for the purpose of determining if these wells were drilled on a single property as defined in IRC sections 614 (a) and if their income and expense should have been reported together on the depletion computation schedule.

  2. The schedule below illustrates what a depletion schedule might look-like per the tax return. "ALL" depletion schedules should show and compute for each property the following:

Oil & Gas Depletion
Leases M N O Y Total Notes
Gross Income from Property $400 $600 $334 $1,334 2a
Direct Operating Expenses $200 $400 $234 $200 $1,034 2b
Intangible Drilling Costs 2c
Allocable Indirect Expenses $50 $100 $40 - $190 2d
Taxable Income from the Property $150 $100 $60 ($200) $110 2e
Percentage Depletion Computation:
a. 15% of Gross Income $60 $90 $50 $ - $200 2f
b. Net Taxable Income $150 $100 $60 $ - $310
Lesser of a. or b. $60 $90 $50 $ - $200 2g
Cost Depletion (From Schedule) $40 $ - $10 $20 $70 2h
Tentative Depletion - Greater of Percentage or Cost $60 $90 $50 $20 $220 2i
Percentage Depletion $60 $90 $50 $ - $200 2f
Limited to 65% of Total Taxable Income (Allocated to Property) $20 $29 $16 $ - $65 * 3
Greater of: Percentage (as Limited) or Cost $40 $29 $16 $20 $105
Percentage Depletion
(Remaining Properties Using % Depletion) $ - $90 $50 $ - $140
Limited to 65% of Total Taxable Income (Allocated to Property) $ - $42 $23 $ - $65 * 3
Allowable Depletion before Barrel Limitation $40 $42 $23 $20 $125
**Barrel Limitation on Percentage Depletion $ - $23 $13 $ - $36 4
Allowable Depletion after Barrel Limitation $40 $19 $10 $20 $89
Depletion Carryover:
Allowable % Depletion BEFORE Considering 65% Taxable Income Limitation $60 $90 $50 $ - $200 2f
Depletion Allowed for the Properties $40 $42 $23 $ - $105
Depletion Carried to Next Year $20 $48 $27 $ - $95 5
* Taxable Income as Corrected
** Based on Depletable Oil Quantity (see explanation below)

The 65 Percent Taxable Limitation. The tentative percentage depletion determined in Step 1 above may be subject to the 65 percent of the taxpayer's taxable income limitation of IRC 613A(d)(1). Determine the 65 percent of the taxpayer's taxable income by:

Starting with the taxpayer's taxable income per return.
  1. Add back to income: Any operating loss carryback (IRC 172); any capital loss carryback (IRC 1212); and in the case of most trusts, distributions to the beneficiaries (see IRC 613A(d)(1)(D)).

  2. Add back to income: Any depletion on production from an oil or gas property which is subject on the provisions of IRC 613A(c) (Exemption for Independent Producers and Royalty Owners).

  3. In the case of an individual: Subtract the "zero bracket amount."

  4. Make appropriate adjustments to income based on audit recommendations.

Multiply the results obtained in above by 0.65. This product is the 65 percent of taxpayer's taxable income limitation. The taxpayer is not allowed Depletion under IRC 613A(c) [percentage depletion] in excess of this amount. If the tentative depletion determined in (i) does not exceed the 65 percent limitation determined above, the tentative depletion is the allowable depletion for those properties. If the tentative depletion determined in (i) exceeds the 65 percent of taxable income limitation determined above. If the tentative depletion computed in (2) exceeds the 65 percent of taxable income limitation, the excess is disallowed. The disallowed percentage depletion must be allocated to each of the properties so that the allowable percentage depletion can be compared with the cost depletion applicable to each property. (The greater of cost depletion or percentage depletion is allowable.) See IRC sections 613(a) and 613A(d)(1).

The Barrel Limitation (Depletable oil quantity). The IRC defines "depletable oil quantity" in terms of barrels per day. It appears that the agent will be better able to make computations and keep the taxpayer's depletion under IRC 613A(c) in perspective if the depletable quantity of oil is expressed in barrels per tax period. We have, therefore, expressed the amount of oil subject to percentage depletion under IRC 613A(c) in barrels per tax period. Include "all" production. Reconcile all production on return. Is production from "flow through entities" included? Spot check price per barrel by dividing gross income by barrels per lease or property. If large differences in price per barrel appears between properties, investigate. Business under common control and members of the same family are treated as one taxpayer, and the tentative quantity must be allocated. See IRC 613A(a)(8). Compute the total of the taxpayer's production of oil in barrels and gas in barrel equivalents for all properties. If the production from the taxpayer's properties exceed 365,000 barrels (1000 barrel per day), then the "depletable oil quantity" will apply. Oil and gas should not be separated for each property. Separate schedules can be prepared for primary production and marginal production. The taxpayer can allocate the barrel limitation to marginal production first, then to primary production. The schedules should provide the information below:

  1. Name of the property AND whether it's marginal or not

  2. Number of barrels of production for the tax period

  3. Convert the gas to equivalent barrels at 1 barrel = 6 MCF of gas

  4. Add barrels of oil to barrels of gas to get total production from property

Note:

Percentage depletion disallowed per Barrel or Depletable oil quantity limitation is not carried forward and is lost forever.

Carryover of Percentage Depletion Disallowed from 65 Percent Limitation. IRC 613A(d)(1) provides that any amount of percentage depletion disallowed because of the 65 percent of taxable income limitation will be treated as an amount allowable under IRC 613A(c) in the following year. In the following year, it will still be subject to the 65 percent of taxable income limitation. The amount of percentage depletion disallowed shall be allocated to the respective properties from which the oil or gas was produced in proportion to the percentage depletion otherwise allowable to such properties under IRC 613A(c).

The allocation of disallowed depletion should be computed in a schedule which has the following column headings:

  1. Name of Property

  2. Cost depletion

  3. Tentative allowable percentage depletion

  4. Disallowed percentage depletion

Allocation of Overhead Expenses

This exhibit is an example of the proper allocation of a company's overhead to the various producing leases. The allocation is based on direct expenses. The allocation is required under Treas. Reg. 1.613–5(a) for the computation of taxable income from the property and the 50 percent of taxable income limitation in computing percentage depletion. See Treas. Reg. 1.613–1.

If a taxpayer has not made an allocation of overhead to the various leases, the agent should scan the depletion computation schedules to decide whether or not an allocation of overhead would probably affect an adjustment in depletion. [How near to the 50 percent (100 percent for taxable years beginning after December 31,1990) net taxable income limitation is the 22 percent, or applicable percent, of gross income?] If adjustment is probable, the agent should scan the unallocated overhead account to determine the proportion that would most likely be allocated to producing leases. If a relatively significant adjustment appears likely, the agent should make the allocation schedule. Computer assistance may be requested in larger cases.

If the taxpayer has made an overhead allocation, the agent should consider the points listed in (2) above. If adjustment to depletion might be significantly affected by a reallocation, the agent should carefully analyze the taxpayer's overhead allocation and verify that it is based on an acceptable method.

Interest expense paid on money borrowed for operating capital is an overhead item which should be allocated to producing and nonproducing activities prior to allocation among the properties. Interest expense paid on money borrowed for investment (equipment, IDC, leasehold, etc.) is a direct expense of those properties and should be allocated to them 100 percent.

If the taxpayer operates his/her properties in conjunction with properties owned by others and charges a fee for services, the fee is not a credit to his/her operating expenses or overhead account; it is an income item. However, to the extent that the taxpayer has expense in connection with earning these fees, the expenses should not be charged to his/her leases.

In examining the allocation, the agent should verify that "nonproducing" activities are consistently treated. If a well was capable of production but was temporarily shut-in (perhaps waiting pipeline connection), its expenses should not be included under nonproducing for allocation between producing and nonproducing activities and also included under producing properties in allocating to the various leases.

Once the allocation is made to specific properties, the agent should verify that the overhead is properly entered in the "line computation" for the property. He/she should be particularly alert for transposition errors between properties with similar names.

Items To Consider During Examination

Leases Expired or Forfeited:

  1. Obtain list of leases charged off description, etc.

  2. Verify cost or basis-expiration date of lease.

  3. Review current lease records for evidence of top leasing.

  4. Are leases involved in a unitization or other reclassification?

  5. Partial abandonments are not deductible.

Intangible Development Costs:

  1. Has proper election been made? Treas. Reg. 1.612-4, IRC 59(e), IRC 291.

  2. Are there advance payments involved? Rev. Rul. 71-252.

  3. Are tangible costs included? Treas. Reg. 1.612-4(a).

  4. Do IDC costs correspond to taxpayer's interest in property? How was it acquired?

  5. If the taxpayer is a corporation which is an integrated oil company, did it reduce its IRC 263(c) deductions (IDC for years after 1982) by 15 percent as required by IRC 291(b)?

Condemned or Expired Royalties:

  1. Determine proper year of deduction based on event taxpayer relied on.

  2. Verify tax basis. Has amount been previously charged off?

  3. Has taxpayer disposed of title to property?

Dry-Hole Costs:

  1. Is expense charged to appropriate property for purpose of computing depletion limitation?

  2. Examine contracts; determine existence of dry-hole contributions, bottom-hole contributions, and farm-ins.

  3. Do dryhole costs include only abandonments? IDC with respect to dryhole costs are deductible under IRC 263(c) unless taxpayer has elected to capitalize IDC.

Depletion:

  1. Is taxable income (before depletion) computed by property? Percentage depletion cannot exceed 50 percent of the property’s taxable income for years beginning prior to 1991. For tax years 1991 through 1997, percentage depletion cannot exceed 100 percent of the property’s taxable income. For taxable years beginning after 12-31-1997 and before 1-1-2008 and tax years beginning 1-1-2009 and before 1-1-2012, the net income limitation does not apply to domestic oil and gas production from marginal properties (note - no provision covers years beginning after 12-31-2007 and before 1-1-2009).

  2. Is depletion claimed on proven properties acquired after 1/1/1975?

  3. IRC 613A(d) limits the percentage depletion to 65 percent of the taxpayer’s current year taxable income, calculated without considering any percentage depletion deductions.

Gross Income :

  1. Obtain detailed schedule of lease operations for current and prior year. (Depletion schedules may serve for this purpose.)

  2. Compare reported receipts, by property, secure explanations for all unusual increases or decreases.

  3. Test income on run tickets for selected leases and selected months.

  4. Working interest income is subject to self-employment tax.

Operating Expenses:

  1. Analyze for large unusual expenses; capital expenditures.

  2. Legal and professional-geological and geophysical.

  3. Determine why some leases have losses.

Alternative Minimum Tax:

  1. Percentage depletion in excess of adjusted basis of leasehold as of beginning of year.

  2. Excess intangible drilling costs is a tax preference item and should include a portion of the overhead. This preference applies only to costs for which the corporation did not elect the optional 60-month write-off under IRC 59(e) for the regular tax.

Sale of Oil and Gas Properties:

  1. Was leasehold basis reduced by allowed or allowable depletion?

  2. Recapture post-'75 intangible development costs? IRC 1254.

  3. Was a continuing economic interest retained?

Joint Interest Accounting:

  1. Are expenses billed to joint owners handled correctly?

  2. Is the taxpayer deducting pro-rata share of expenses? Test selected leases-consider those operating at a loss and those with unusually large expenses.

  3. Does an increasing credit balance in the oil and gas payout account represent income that should be reported?

Mandatory Referrals:

  1. Engineers-

    • Cases with Activity Codes 219-225 & 290

    • Cases with Activity Code 483 and Gross Receipts/Deductions $1,000,000 and above.

  2. Financial Products-