TABLE OF CONTENTS

OIL AND GAS INDUSTRY

Index to Exhibits

Foreword

Chapter 1, Oil and Gas IndustryOverview

General Description of the Industry

Mineral Interests

Acquisition Through Mineral Lease

Acquisition in Fee

Property Overview

Types of Ownership Interest

Tract or Parcel

Separate Deposits

Unitization

Accounting Methods

Successful Efforts Method

Full Cost Method

Accounting Records

Chapter 2, Oil and Gas Industry IssuesIssues Related to an Oil and Gas Entity and Activity

Overview

Unproductive Issues

Productive Issues

Unique Issues

Uniform Capitalization Rules

Assistance in IRC Section 263A

General Issues [Non-Oil and Gas]

Chapter 3, Oil and Gas Audit TechniquesExamination of an Oil and Gas Entity and Activity

Engineering Referral

Initial Interview Questions

Initial Information Document Request

Accounting Methods

Property Definition

Unitization

Areas Typical of an Oil And Gas Entity

Gross Income

Lease Bonus

Delay Rentals

Royalty Income

Advance Royalties

Minimum Royalties

Shut in Royalties

Production Payments

Damages

Shooting Rights

Uniform Capitalization Rules - IRC section 263A

Produced Property

Predevelopment Expenses

Interest Capitalization

Allocation of Indirect Expenses

Conclusion

Auditing Techniques

Leasehold Cost

Geological and Geophysical Costs

Abandonment Cost

Audit Techniques

Lease Operating Expense

Bad Debts (Joint Interest Owners)

Intangible Drilling Cost

Audit Techniques

Lease and Well Equipment

Depletion

Economic Interest

Cost Depletion

Units Sold

Adjusted Basis of Property

Cost Depletion on Wildcat Acreage

Percentage Depletion

Independent Producer

Transfers of Proven Properties

Gross Income from the Property

Net Income of the Property

Expenses of the Property

Overhead Allocation

Audit Techniques

Information Required to Compute Depletion Allowance

Alternative Minimum Tax

Percentage Depletion

Intangible Drilling Costs

Alternative Tax Energy Preference Deduction

Qualified Exploratory Costs

Marginal Production

Phase Out of the Deduction

Audit Techniques

Alternative Tax Energy Preference Deduction

Self-Employment Income

Passive Activity Loss Limitations

Oil and Gas Activities

Portfolio Income

Chapter 4, Financial ProductsPotential Area of Concern Related to Oil and Gas

Energy Markets and the Participants

ash Market

Forward Market

Futures Market

Options Contracts

Market Participants in Forward and Futures Contracts

Commodity Notional Contracts

Commodity Notional Swap

Use of Commodity Notional Swap to Hedge Risk

Glossary

Technical ReferencesGeneral Counsel Memorandums (GCM) and Court Cases

Revenue RulingsTR-2Assignments, Sales and Exchanges

Capital Expenditures

Definition of Property

Cost Depletion

Depletion, Gross Income, Net Income

Percentage Depletion

Geological and Geophysical Costs

Intangible Drilling and Development Cost

Nonconventional Fuel Credit

Nonrecourse Loan

Partnerships

Sharing Arrangements

Miscellaneous

INDEX TO EXHIBITS

No.TitleExplanation1-1Oil and Gas LeasePetroleum companies obtain the rights to explore, drill, andand Mineral Deedproduce subsurface minerals by entering into an oil and gasagreement or lease with the landowner. An oil and gas leaseembodies the legal rights, privileges and duties pertaining tothe lessor and lessee. The lessor is the mineral interest ownerwho transfers the working interest to the lessee who retains aroyalty interest. The mineral lease is a very important legaldocument to the petroleum industry and provides theframework for all the activities that follow. It can be a usefulauditing tool, because it provides a description of the property, identifies the royalty owner, and can give details of such itemsas delay rentals, lease bonus, unitizations, and primary terms.

1-2AccountingWhen a joint interest situation is created, the parties involvedProcedure(i.e., the operator and nonoperators) generally execute anAccompanying aoperating agreement. The normal form used for the operatingJoint Operatingagreement is AAPL Form 601. The joint operating agreementAgreementdelineates the responsibilities and duties of the operator andnonoperators. It may cover only drilling operations, or it maycover both, exploration and production.

1-3Division OrderPrior to the sale of oil or gas covered by a particular lease, adivision order is prepared and signed by all interest owners.

The division order is a necessary instrument in order for theoperator to orderly and legally collect the oil and gas revenuesand to pay the correct owners of the minerals.

1-4Division of InterestFor accounting purposes, the information on the division orderis usually condensed into a more usable format that can be putinto the lease file for easy reference. Such a division ofinterest will be prepared for each property and shows eachowner's name, identification number, and fractional interest.

2-1Example of TaxThis exhibit shows the effect of the application of the taxBenefit for IDCbenefit rule when computing the tax preference item for IDCwith AMTwhen one has both the IDC preference and the depletionpreference.

3-1Texas RailroadThis exhibit provides explanations for various forms availableCommission Formsfrom the Texas Railroad Commission.

FOREWORD

The purpose of this Market Segment Specialization Program (MSSP) audittechniques guide is to provide examiners reference material relating to the oil and gasindustry for General Program examinations. This guide is a compilation of varioussources offering a quick reference guide to examiners. Its intent is to supplement theoil and gas training material published and taught in formal training. Reference is notmade to all of the facets or issues of the oil and gas industry. However, this guidewill enable one to become familiar with the basic operations and common terminologyof the oil and gas industry, including brief references to royalty owners. Examinersare still encouraged to continue to use the specialized audit techniques handbook(IRM 4232.8, Techniques Handbook for Specialized Industries -- Oil and Gas) andconsult petroleum engineers when necessary, as well as other outside referencematerial written on the oil and gas industry. The Midstates Regional office houses the Petroleum Industry Program (PIP) whichhas specialists in the oil and gas industry. These specialists are geared mainlytowards issues that affect CEP examinations. However, if an examiner identifies acomplex issue in a General Program case and needs assistance, PIP could beconsulted. It has become common knowledge that the oil and gas industry has expanded theiractivities into financial products. This guide will introduce you to the vehicles thatare being used to hedge and claim an ordinary loss versus a capital loss. Therevised specialized audit techniques handbook mentioned above should be consultedfor further guidance in this area.

Reference materials used in preparing this guide include the following:

1.Internal Revenue Code of 1986.

2.Income Tax Regulations.

3.Oil and Gas Taxation, by John P. Klingstedt, Horace R. Brock, and Richard S. Mark.

4.Income Taxation of Natural Resources 1992, by C.W. Russell, C.P.A.

5.Internal Revenue Manual 4232.8, Techniques Handbook for SpecializedIndustries - Oil and Gas.

6.Publication 641, Service 1 Basic Volume 1953-1990, Bulletin Index-DigestSystem, Volumes I and II.

7.Oil and Gas Units I and II, Texts (courses 3185 and 3186).

Chapter 1OIL AND GAS INDUSTRY

OVERVIEW

The oil and gas industry has been in an economic slump since the mid-1980's. Therehave not been significant domestic explorations that have been successful. In 1992, amanufacturer of equipment related to drilling of oil and gas wells said it was closing itsdoors because the life of its product was 20 years and a new order had not beenreceived domestically for 10 years. Also, there have been newspaper articles in thepast 3 years expressing concerns from companies based in Oklahoma over the drop inthe price of natural gas. However, this concern has been alleviated somewhat as theprice of natural gas has steadily increased since then, to a new 5-year high in March1993. In March 1994, an article in the Dallas Morning News provided some statisticsthat depicted an industry in distress. It stated the following:

1.Oil and gas industry employment in the United States slipped to 1.43 million lastyear, the lowest in more than 20 years.

2.U.S. oil production fell to 6.8 million barrels per day in 1993, the lowest since1958.3.U.S. oil imports continue to rise reaching 6.7 million barrels per day last year. The Service expended extensive time and resources auditing the oil and gas industryand related businesses in the 1970's and early 1980's. With the passage of the CrudeOil Windfall Profit Tax Act of 1980, the Service expanded its resources to include theexamination of this excise tax in conjunction with the income tax considerations of theoil and gas industry. Since the mid-1970's, there have been regulations, legislation, and judicial decisionsthat have narrowed the gap with regard to differences of opinions in the interpretationsof various sections of the law. The various interpretations related to Congress' intentas to how this particular area of law is to be applied. What does the future hold for oil and gas? It appears that the basic oil and gas issuesexist. There is no new wrinkle in the industry such as we saw in tax shelters involvingcomputers, real estate, etc. However, there does appear to be an area that has goodpotential for auditing. Due to the declining oil and gas prices, there has been increasedactivity by natural resource companies in the financial markets, trading on theexchange and off exchange. Examiners should be cognizant of financial producttransactions when examining oil and gas companies.

GENERAL DESCRIPTION OF THE INDUSTRY

Mineral Interests

To determine the proper tax treatment of oil and gas transactions, one needs to have abasic understanding of the various mineral interests. An operator may acquire themineral rights in two ways. The first, and most common, method is to acquire theright to the minerals through a mineral lease. The other way is to acquire the mineralinterest in fee.

Acquisition Through Mineral Lease

The interest begins with the landowner. The landowner owns the land in fee, includingthe minerals on and below the surface, but does not possess the financial resources ortechnology required to drill a well. If the landowner does not want to sell the mineralrights outright, he or she can convey the rights to develop the minerals through alease. (See Exhibit 1-1 for an example of a mineral lease.) The landowner typicallyleases the mineral interest and retains a royalty interest, usually between a one-eighthand three-eighths interest. After leasing the property and retaining a royalty interest, the landowner takes on a new posture in the field of oil and gas; he or she becomes afee royalty owner, as well as the landowner. It should be noted that the owner ofthe land in fee can dispose of all or part of the mineral rights and sell them to a thirdparty. The third party which purchases the mineral rights would become a mineralowner without being a landowner. The landowner will have very few expensesassociated with the mineral interest. If the property is producing, the landowner willhave severance or production taxes, depletion, and, possibly, a small amount ofoverhead. The royalty owner generally receives one-eighth of all the oil and gas produced fromthe lease as a result of retaining a royalty interest of the same percentage in this type oftransaction. A royalty interest entitles its owner to share in the production from themineral deposits, free of development and operating costs and extends over theproductive life of the property leased. The lessee in the transaction usually acquiresthe balance of the mineral rights, less the percentage retained by the royalty owner, inthe form of a working interest. A working interest not only entitles its owner to sharein the production, but also requires the owner to bear their share of the developing andoperating costs. The working interest owner may not have the working capital necessary to drill thewell or may want to share the risk. One may, subject to certain restrictions, sell ordispose of all or part of the working interest in the total production and in the processcreate additional subdivisions of it such as an overriding royalty interest, productionpayments, net profits interest, etc. If some of the working interest is sold to otherinvestors, a joint venture is created. (See Exhibit 1-2 for an example of theAccounting Procedure accompanying a Joint Operating Agreement.) The venture maybe a formal partnership with a return being filed, or it may elect out of the partnership filing requirements. It is not unusual for a lessee to be involved in working interestsand have an overriding royalty interest in working interests. A royalty interest can be acquired by purchase from the landowner, who may sell anentire interest or any fraction thereof. This usually occurs after a lease has beengranted for the development of the property and there appears to be a prospect offuture production. The purchase is usually made by an investor or royalty dealer. As the taxpayer branches out from developing and operating the mineral interest torefining and retailing the minerals extracted, the return becomes more complex. Adetermination of whether the taxpayer is an independent producer or integrated oilcompany must be made; as the tax treatment is quite different for each. Anindependent producer, as defined by IRC section 613A(d), is a producer who does nothave more than $5 million in retail sales of oil and gas in a year or one who does notrefine more than 50,000 barrels of crude oil on any day during the year. A qualifiedindependent producer will be denied a percentage depletion deduction on productionvolumes which exceed the average daily production of 1,000 barrels of crude oil. Anintegrated oil company is a producer which is also either a retailer, which sells morethan $5 million of oil or gas in a year, or a refiner, which refines more than 50,000barrels of oil on, any day during the year. However, it should be noted that theclassification of an independent producer can be denied, even when the producer doesnot own a refinery, when an associated company refines more than 50,000 barrels inany day of the year. This is especially true when some of the producer's oil or gas istraced to the associated company's refinery, even through an exchange with a thirdparty.

Acquisition in Fee

When the operator acquires the mineral rights in fee, the operator will have the right to100 percent of the income generated from the production. Also, 100 percent of thecost to drill and complete the wells on the property will be incurred. Such an interestis described as an 8/8s mineral interest or working interest. The cost incurred to purchase the fee mineral interest should be capitalized andrecovered through depletion. If the mineral owner drills a well, the intangible drillingcosts (IDC) should be capitalized or deducted depending upon the taxpayer's election. Tangible costs should be capitalized and recovered through depreciation. Expensesincurred to operate the property would be an allowable ordinary and necessarybusiness expense deduction.

Figure 1-1

Below is an illustration of the various oil and gas property interests.

Illustration of the various oil and gas property interests

ORIGINALWORKINGINTERESTLandowner RoyaltyMINERALFEEOverriding Royalties andNet Profits InterestsConvertible OverridingRoyaltiesWorkingPaymentInterest[Oil Payment]

Production

The following, Scenarios A through E, illustrates how one property containingminerals can be carved up into various mineral interests.

Scenario A

FEE OWNER A -

100 PERCENT INTEREST

Owner A holds the fee interest in minerals. A also owns all of the rights in perpetuity.

Scenario B

Owner A leases the mineral rights to B (the lessee), retaining a 1/5 (20 percent) basic(landowner's) royalty. The lease contract is for a primary term and as long thereafteras oil or gas is produced. A (the lessor) will receive 20 percent of all productionproceeds and B will receive 80 percent (4/5) of production proceeds. If the primaryterm expires, or if oil or gas subsequently ceases, the lease expires and all rights revertto A, the mineral rights owner.

INTEREST BEFORE SCENARIO BFEE OWNER A -

100 PERCENT INTEREST

INTEREST AFTERSCENARIO BA - 20 PERCENT FEE

OWNER'S ROYALTYB - 80 PERCENT WORKING

INTEREST

Scenario C

B subleases the property to C, retaining a 1/10 (10 percent) overriding royalty(ORRI). The ORRI lasts only as long as the original lease contract between A and Bis in force. Now A is entitled to 20 percent of the production, B is entitled to 10percent, and C (the new working interest owner) is entitled to 70 percent.

INTEREST AFTERSCENARIO CA - 20 PERCENT FEE

OWNER'S ROYALTYB - 10 PERCENT (ORRI)

C - 70 PERCENT WORKING

INTEREST

INTEREST BEFORE SCENARIO DA - 20 PERCENT FEE

OWNER'S ROYALTYB - 10 PERCENT (ORRI)

C - 70 PERCENT

WORKING INTEREST

Scenario D

C carves out and sells to D a production payment that entitles D to receive 500,000MCF of gas, payable out of 60 percent of the net working interests share of gas eachmonth (60 percent of 70 percent = 42 percent of the total mineral interest). When theproduction payment has been satisfied, D will have no further interest in the minerals.

C will receive 28 percent (40 percent of 70 percent) of production until the productionpayment is paid out. After the pay out is completed, C then will begin to receive 70percent of the remainder of the productive life of the property.

INTEREST BEFORE SCENARIO CA - 20 PERCENT FEE

OWNER'S ROYALTYB - 80 PERCENT

WORKING INTEREST

C - 28 PERCENT

WORKING

INTEREST

INTEREST AFTERSCENARIO DA - 20 PERCENT FEE

OWNER'S ROYALTYB - 10 PERCENT (ORRI)

D - 42 PERCENT

PROD PYMNT

C - 70 PERCENT

WORKING

INTEREST

Scenario E

C sells one-half (50 percent) of the net working interest to E. C and E (now ownersof undivided interests in the working interest) each will receive 14 percent (50 percentx 40 percent x 70 percent) of the production until the production payment to D issatisfied. After pay out of the production payment to D, C, and E will receive 35percent (50 percent x 70 percent of the working interest) of production.

INTEREST BEFORESCENARIO EA - 20 PERCENT FEE

OWNER'S ROYALTYB - 10 PERCENT (ORRI)

D - 42 PERCENTC - 35 PERCENT PROD PYMNT

WORKING

INTERESTC - 28 PERCENT

WORKING

INTEREST

INTEREST AFTERSCENARIO EA - 20 PERCENT FEE

OWNER'S ROYALTYB - 10 PERCENT (ORRI)

D - 42 PERCENTC - 35 PERCENT

PROD PYMNT WORKING

INTERESTC - 14 PERCENT

WORKING

INTEREST

E - 35 PERCENT

WORKING

INTEREST

E - 14 PERCENT

WORKING

INTEREST

Property Overview

The mineral interests concept and knowing who the various parties are and their titlesin the world of oil and gas are vital information to know when being introduced to oiland gas. Next one must become familiar with the property concept. This concept isthe basis for the use of the property unit as the tax entity for purposes of depletion, abandonment losses, recapture rules, etc. The property definition set forth in IRCsection 614 emphasizes separateness, specifically, the separateness of different types ofinterests, geographic locations (surface), and oil and gas deposits (subsurface). IRCsection 614(a) defines the term property to mean *** each separate interest owned bythe taxpayer in each mineral deposit in each separate tract or parcel of land. The taxpayer might manipulate the definition of property to attempt to take largerdeductions for depletion, to take a premature deduction for an abandonment, or toreduce its recapture potential. Many taxpayers will account for their income andexpenses on a well-by-well basis for their accounting records. Others might segregatetheir income and expenses by prospect. Since their records are set up this way, theymay not want to go through the inconvenience and cost to convert the records toreflect the property concept for tax purposes.

TYPES OF OWNERSHIP INTEREST

Each different type of interest is treated as a separate property. For example, if ataxpayer owns a royalty interest and a working interest in the same tract of land, thetaxpayer would have two separate tax properties. This position is set out in Rev. Rul. 77-176, 1977-1 C.B. 77.

Tract or Parcel

A single lease may cover a number of separate tracts or parcels of land. The fact thatseveral tracts are covered by a single lease does not mean that they are automaticallyone property. The deciding factor that determines whether or not two or more tractsof land will be considered one property is whether the tracts are contiguous or have acommon side. Each separate tract refers to the physical area which is delineated bythe legal description. Tracts which touch at a corner are adjacent, not contiguous, andwould be treated as separate properties. All contiguous tracts or parcels of landobtained on the same day from the same person must be treated as one property inaccordance with Treas. Reg. section 1.614-1(a)(3).

Separate Deposits

IRC section 614(a) states the general rule that each separate mineral deposit on eachtract will be treated as a separate property. However, IRC section 614(b)(1) and (2) provide a special rule which allows operating mineral interests in oil and gas depositsin a tract or parcel to be treated as one property, unless an election is made to treat thedeposits separately. When an election is made to treat the deposits as separateproperties, production from the deposits must be accounted for separately.

Unitization

To develop a reservoir more effectively, a number of different property owners maycombine their properties into a single unit. Some states require unitization within eachfield or reservoir. Whether or not the unitization is voluntary or involuntary, the effectis the same. Several separate properties are combined within a unitization agreement. Thus, one property is created for the taxpayers. Figure 1-2 below illustrates the difference between adjacent and contiguous areas.

Figure 1-2

Figure 1-2ABC

1.A and B are contiguous properties, treated as one property, because they have a common side.

2.B and C are adjacent properties, treated as separate properties, because they only touch at acorner. They do not have a common side.

ACCOUNTING METHODS

When auditing a taxpayer in the oil and gas industry, it is important to determine themethod of accounting used for book and tax purposes. An individual landowner/lessorusually uses the cash method of accounting for income and expenses. The workinginterest owner/lessee will use either the cash or accrual method. In conjunction witheither method, the taxpayer may also use the successful efforts (SE) method or the fullcost (FC) method of accounting for financial statement purposes. Both methods, FCand SE, were developed by the oil and gas industry to account for its operations forfinancial purposes. Although neither method is used for tax purposes, it is importantto understand the method the taxpayer uses for financial record keeping. Thisknowledge will help to understand the adjusting entries made at year-end to convertthe books to income tax reporting and determine whether they are properly handled.

Successful Efforts (SE) Method

The Financial Accounting Standards Board (FASB) has issued FASB Statement No. 19 dealing with the successful efforts method. Under the SE method, costs incurred insearching for, acquiring, and developing oil and gas reserves are capitalized if theydirectly result in producing reserves. Costs which are attributable to activities that donot result in finding, acquiring, or developing specific reserves are charged to expense. The cost center for the SE method is a lease, field, or reservoir.

The various types of costs are treated under the SE method as follows:

1.Acquisition Costs: They are capitalized to unproven property until provedreserves are found or until the property is abandoned or impaired (a partialabandonment). If adequate reserves are discovered, the property is reclassifiedfrom unproven property to proven property. For tax purposes, acquisition costsare handled the same way except the cost cannot be partially written off as animpairment expense. The property must be abandoned before any cost may bewritten off.

2.Exploration Costs: They are recorded in two different ways, depending upon thetype of costs incurred.

a.Nondrilling Costs: Examples of these type of costs are geological andgeophysical (G & G) costs, costs of carrying and retaining undevelopedproperties, and dry hole and bottom hole contributions. These types of costsare expensed as they are incurred. For tax purposes, nondrilling costs arecapitalized to the applicable property.

b.Drilling Costs: They are treated differently depending on whether the welldrilled is classified as an exploratory well or a developmental well. Anexploratory well is a well drilled in an unproven area. A developmental well isa well drilled to produce from a proven reservoir.

1)If an exploratory well is a dry hole, the costs incurred in drilling the wellare expensed. If the exploratory well is successful, the costs incurred indrilling the well are capitalized to wells and related equipment andfacilities.

2)The costs incurred in drilling developmental wells are capitalized torelated equipment and facilities even if a dry hole is drilled.

For tax purposes, there is no distinction made between exploratory anddevelopmental wells. Intangible drilling costs (IDC) for either type of well arecapitalized unless an election is made to expense them in accordance with IRCsection 263(c). It should be noted that only domestic IDC can be expensed. Foreign IDC is capitalized and amortized over a 10-year period. Integrated oilcompanies which elect to expense domestic IDC may only expense 70 percent ofthe IDC incurred. The remaining domestic IDC, 30 percent, must be capitalizedand amortized over a 5-year period. Dry hole costs for either type of well may beexpensed unless the taxpayer capitalizes IDC. If the taxpayer capitalizes IDC, thenan election is required to expense dry hole costs in accordance with Treas. Reg. section 1.612-4(b)(4). Thus, an M-1 adjustment would be required for all IDCincurred unless the IDC is incurred on an exploratory dry hole. The costs associated with tangible well equipment and facilities are capitalized, regardless of the type of well drilled. For tax purposes, certain costs associatedwith such equipment are eligible for treatment as deductible IDC. Taxdepreciation methods usually allow for a more accelerated rate of depreciationthan book or financial depreciation. Also, book depreciation will be computed on the developmental dry holes and IDC which are capitalized for book purposes butexpensed for tax purposes. Therefore, an M-1 adjustment will be required on thedifference between the amount of book and tax depreciation.

3.Production Costs: These costs are expensed as incurred, which is the sametreatment used for tax purposes. It should be noted, however, that many taxpayerserroneously expense overhead attributable to either acquisition or explorationactivities as production costs. Overhead attributable to acquisition and explorationcosts must be capitalized.

4.Depletion: This usually requires an M-1 adjustment. Although the cost depletionformula is the same for book and tax purposes, the amount for the basis used in thecomputation of cost depletion will vary due to the difference in capitalization. Inaddition, many taxpayers will be allowed to use a larger percentage depletiondeduction.

Full Cost (FC) Method

Under the FC method, all costs incurred in exploring, acquiring, and developing oiland gas reserves in a cost center are capitalized.

1.Geological and geophysical (G & G) studies, successful and unsuccessful, arecapitalized for book and financial purposes. For tax purposes, successful G & Gcosts are capitalized and unsuccessful G & G costs are expensed. An M-1adjustment is required for the amount of unsuccessful G & G costs expensed.

2.Delay rental costs are capitalized for book and financial purposes.

3.Exploratory dry hole costs are capitalized for book and financial purposes. For taxpurposes, all dry hole costs (exploratory or developmental) are capitalized unlessthe taxpayer elects to expense them. Since most taxpayers expense these costs fortax purposes, an M-1 adjustment is required.

4.Impaired or abandoned property costs remain capitalized in the cost center forbook and financial purposes. For tax purposes, no deduction is allowed unless aproperty is totally worthless. An M-1 adjustment is required only when anabandonment is claimed for tax purposes.

5.General and administrative costs which are not associated with acquisition, exploration, and development activities are expensed. However, overhead that canbe associated with acquisition, exploration, and development activities iscapitalized. The costs are handled the same way for tax purposes.

6.Depletion usually will require an M-1 adjustment. In many instances, taxpayersmay be able to claim a larger percentage depletion deduction in lieu of costdepletion. Even where cost depletion is claimed for book and financial purposes because of the different capitalization rules, the amount of cost depletion allowablewill vary. Figure 3-1 below provides a comparison of the three methods: Successful Efforts, Full Cost, and Tax.

Figure 1-3Comparison of the Successful Efforts Method,

Full Cost Method, and TaxType of CostSEFCTaxGeological and GeophysicalECC (Successful)

E (Unsuccessful)

AcquisitionCCC

Exploratory Dry HoleECE (IRC section 165 Loss)

Exploratory Well, SuccessfulCCE*

Developmental Dry HoleCCE (IRC section 165 Loss)

Developmental Well, SuccessfulCCE*

ProductionEEE

Amortization Cost Center*******

Note: E = Expense and C = Capitalize

* =Taxpayers may elect to expense IDC. Although IDC is capitalin nature, most taxpayers elect to expense IDC. The tangibleportion is capitalized and depreciated. The typical well isusually two-thirds IDC and one-third tangible well equipmentand facilities.

** =Property, Field, or Reservoir

*** =Country

ACCOUNTING RECORDS

The source documents available to verify income and expenses will depend on the typeof interest the taxpayer owns, but some records are common to all interest holders. Each owner should have a copy of the lease, the division order or division of interest, and check stubs or remittance slips. The lease will show the royalty interest retained, the amount of delay rentals, and the primary term of the agreement. (See Exhibit 1-1for a copy of the mineral lease.) The division order is a necessary instrument for theoperator to orderly and legally collect the oil and gas revenues and pay the correctowners of the minerals. (See Exhibit 1-3 for an example of a division order.) For accounting purposes, the information on the division order is usually condensed into amore usable format that can be put into the lease file for easy reference. Such adivision of interest is prepared for each property and shows each owner's name, identification number, and fractional interest. (See Exhibit 1-4 for an example of adivision of interest.) The check stubs show the type and percentage of interest owned, the quantity of minerals sold, the severance taxes withheld, and the date and amountpaid to the interest owner. (A sample standardize revenue check stub can be obtainedfrom the Council of Petroleum Accountants Society (COPAS), Arlington, Texas.) The royalty owner will have a copy of the lease and the remittance slips, along withpossible correspondence about the property. The nonoperating working interest owner will have the following:

1.Copy of the lease2.Remittance slips3.Possible correspondence about the property4.Copy of the operating agreement5."Authorizations for Expenditures or AFEs6.Periodic statements from the operator showing expenses incurred with theclassification of the expenses for tax purposes. Operator statements should not be accepted prima facie. If costs appear to be out ofline, further audit work should be performed. A comparison should be made between the actual costs incurred in drilling the welland those shown on the AFE. An AFE is a budget that must be approved by theoperator and all the other working interest owners. It is detailed enough for thenonoperating working interest owners to determine whether the budgeted amounts arereasonable. If the expenses deducted are not close to the budgeted amounts and noreasonable explanation is given, then the examining officer should ask the taxpayer toobtain the invoices and contracts necessary to substantiate the deductions from theoperator. The costs should be allowed if the payments were made timely to theoperator and they are in line with the AFE and appear reasonable and correctlyclassified on the operator's statement. The operator oversees the development, drilling, completion, and day-to-day operationof a property. The operator is almost always a working interest owner as well as anoperator. In addition to the records mentioned above, the operator will generally haveall of the original source documents to verify income, expenses, and capital costs onthe operated property. Further, the operator is responsible for filing state reports inrelation to pluggings and abandonments, well completions, etc. and will have copies ofthese reports.

Exhibit 1-1 (1 of 3)

OIL AND GAS LEASEOKLAHOMA--SUIT-IN ROYALTY, POOLING

THIS AGREEMENT, made and entered into this _____ day of __________, 19 ___, by and between ____________________ hereinaftercalled Lessor, and ____________________, hereinafter called Lessee.

WITNESSETH:

1.That Lessor, in consideration of the sum of ____________________ Dollars, ($__________) receipt of which is herebyacknowledged, other good and valuable considerations, and the mutual covenants and agreements contained herein, does hereby grant, bargain, lease and let unto the Lessee, the land described hereinafter, for the purpose of carrying on geological, geophysical and other exploratory work, including core drilling, the right to enter upon said lands for such purposes without any additional payments, and for the purpose of drilling, mining and operating for, producing, and saving all of the oil, gas, casehead gas, casehead gasoline and all other gases and their respectiveconstituent vapors, and constructing roads, laying pipe lines, building tanks, storing oil, building power stations, telephone lines and otherstructures thereon necessary or convenient for the economical operation of said land, to produce, save, take care of, and manufacture all of suchsubstances, and also for housing and boarding employees, said tract of land with any reversionary rights therein being situated in the County of____________________ State of Oklahoma, and described as follows to wit: containing ____________________ acres, more or less.

2.This Lease shall remain in full force and effect for a term of ______ years and as long thereafter as oil, gas, casinghead gas, casinghead gasoline or any of the products covered by this Lease is, or can be produced.

3.The Lessee shall deliver to Lessor as royalty, free of cost, on the lease, or into the pipe line to which Lessee may connect its wellsthe equal one-eighth part of all oil produced and saved from the leased premises, or at the Lessee's option may pay to the Lessor for such one- eighth royalty the market price for oil of like grade and gravity prevailing on the day such oil is run into the pipe line or into storage tanks.

4.The Lessee shall pay to Lessor for gas produced from any oil well and used by the Lessee for the manufacture of gasoline or anyother product as royalty 1/8 of the market value of such gas at the mouth of the well; if such gas is sold by the Lessee, they as royalty 1/8 of theproceeds of the sale thereof at the mouth of the well. The Lessee shall pay Lessor as royalty 1/8 of the proceeds from the sale of gas as such atthe mouth of the well where gas is found, and where such gas is not sold or used, Lessee shall pay or tender annually at the end of each yearlyperiod during which such gas is not sold or used, as royalty, an amount equal to the delay rental provided for in paragraph 5 hereof, and whilesaid shut-in royalty is so paid or tendered this Lease shall be held as a producing Lease under paragraph 2 hereof.

5.If operations for the drilling of a well for oil or gas are not commenced on said land on or before the _____ day of_________________, 19___, this Lease shall terminate as to both parties, unless the Lessee shall on or before said date pay or tender to theLessor, or for the Lessor's credit in the ____________________ Bank at ____________________, or its successors, which Bank and itssuccessors shall be the Lessor's agent and shall continue as the depository of any and all sums payable under this Lease regardless of change ofownership in said land, or in the oil and gas or in the rentals to accrue hereunder, the sum of $_______, which shall operate as a rental and coverthe privilege of deferring the commencement of operations for drilling for a period of one year. In like manner and upon like payments or tendersthe commencement of operations for drilling may be further deferred for like periods successively. All payments or tenders may be made bycheck or draft of Lessee, mailed or delivered on or before the rental paying date, either direct to the Lessor, or to said depository Bank, and it isunderstood and agreed that the consideration first recited herein, the down payment, covers not only the privileges granted to the date when saidfirst rental is payable as aforesaid, but also the Lessee's option of extending that period as aforesaid and any and all other rights conferred herein. Notwithstanding the death of the Lessor, the payment or tender of rentals in the manner above provided for shall be binding on the heirs, devisees, executors, administrators, and legal representatives of such persons.

6.If at any time prior to the discovery of oil or gas on this land and during the term of this Lease, the Lessee shall drill a dry hole, orholes on this land, this Lease shall not terminate, provided operations for the drilling of a well are commenced by the next ensuing rental payingdate, or provided the Lessee begins or resumes payment of rentals in the manner and amount herein above provided for, and in this event thepreceding paragraphs hereof governing the payment of rentals and the manner and effect thereof shall continue in full force.

7.In case said Lessor owes a lessor interest in the above described land than the entire and undivided fee simple estate therein, thenthe rentals and royalties herein provided for shall be paid to said Lessor only in the proportion that his interest bears to the whole and undividedfee. There shall be no relationship whatsoever between royalties and rentals insofar as the paragraph is concerned in determining the amount ofroyalties to be paid to the Lessor as provided for herein above. Should the interest of the Lessor in the above described lands increase during theterm hereof by reason of any reversionary interest then the rental shall be increased at the next succeeding rental anniversary after such reversion.

8.The Lessee shall have the right to use, free of cost, gas, oil and water found on this land for its operations thereon, except waterfrom the wells of the Lessor. When required by the Lessor, the Lessee shall bury its pipe lines below plow depth and shall pay for damagecaused by its operations to growing crops on said land. No well shall be drilled nearer than 200 feet to the house or barn on said premises as ofthe date of the Lease without the written consent of the Lessor. Lessee shall have the right at any time during, or after the expiration of this Leaseto remove all machinery, fixtures, houses, buildings and other structures placed on said premises, including the right to draw and remove allcasing, but Lessee shall be under no obligation to do so, nor shall Lessee be under any obligation to restore the surface to its original condition, where any alterations or changes were due to operations reasonably necessary under the terms of this Lease.

This material provided courtesy of R.P.I. Institutional Services, Inc., New York, NY.

Exhibit 1-1 (2 of 3)

9.If the estate of either party hereto is assigned, and the privilege of resigning in whole or in part is expressly allowed, the covenantshereof shall extend to the heirs, devisees, executors, administrators, successors, and assigns, but no change of ownership in the land, or in therentals, or in the royalties or in any sum due under this Lease shall be binding on the Lessee until it has been furnished with either the originalrecorded instrument of conveyance, or a duly certified copy thereof, or a certified copy of the will of any deceased owner and of the probatethereof, or a certified copy of the proceedings showing the appointment of an administrator or executor for the estate of any deceased owner, whichever is appropriate, together with all recorded instruments of conveyance, or duly certified copies thereof necessary in showing a completechain of title out of the Lessor to the full interest claimed and all advance payment of rentals made hereunder before receipt of such documentsshall be binding on any direct or indirect assignee, grantee, devisee, administrator, executor or heir of Lessor.

10.If the leased premises are now or shall hereafter be owned in severalty or in separate tracts, the premises shall nevertheless bedeveloped and operated as one Lease and there shall be no obligation on the part of the Lessee to offset wells on separate tracts into which theland covered by this Lease may hereafter be divided by sale, devise, descent, or otherwise, or to furnish separate measuring or receiving tanks. Itis hereby agreed that in the event this Lease shall be assigned as to a part or as to parts of the above described land and the holder or owner of anysuch part or parts shall make default in the payment of the proportionate part of the rent due from him or them, such default shall not operate todefeat or affect this Lease insofar as it covers a part of said land upon which the Lessee or any assignee hereof shall make due payment of saidrentals.

11.Lessor hereby warrants and agrees to defend the title to the land herein described and agrees that the Lessee, at its option may payand discharge, in whole or in part any taxes, mortgages, or other liens existing, levied, or assessed on or against the above described lands, and inthe event it exercises such option, it shall be subrogated to the rights of any holder or holders thereof and may reimburse itself by applying to thedischarge of any such mortgage, tax, or other lien, any royalty or rental accruing hereunder.

12.Notwithstanding anything in this Lease to the contrary, it is expressly agreed that if the Lessee shall commence operations for thedrilling of a well at any time while this Lease is in force, this Lease shall remain in full force and effect and its terms shall continue so long assuch operations are prosecuted, and if production results therefrom, then as long as such production continues.

13.If within the primary terms of this Lease, production on the leased premises shall cease from any cause, this Lease shall notterminate provided operations for drilling of a well shall be commenced before or on the next ensuring rental paying date; or provided Lesseebegins or resumes the payment of rentals in the manner and amount herein above provided for. If after the expiration of the primary term of thisLease, production on the leased premises shall cease from any cause, this Lease shall not terminate provided Lessee resumes operations fordrilling a well within 60 days from such cessation, and this Lease shall remain in force during the prosecution of such operations, and, ifproduction results therefrom, then as long as production continues.

14.Lessee may at any time surrender or cancel this Lease in whole or in part by delivering or mailing such release to the Lessor, or byplacing the release of record in the County where said land is situated. In this Lease is surrendered or canceled as to only a portion of the acreagecovered hereby, then all payments and liabilities thereafter accruing under the terms of this Lease as to the portion canceled, shall cease andterminate and any rentals thereafter paid may be apportioned on an acreage basis, but as to the portion of the acreage not released the terms andprovisions of this Lease shall continue and remain in full force and effect for all purposes.

15.All provisions hereof, express or implied, shall be subject to all federal and state laws, and the orders, rules, or regulations of allgovernmental agencies administering the same, and this Lease shall not be in any way terminated wholly or partially, nor shall the Lessee beliable in damages for failure to comply with any of the express or implied provisions hereof if such failure accords with any such laws, orders, rules or regulations. If Lessee shall be prevented during the last year of the primary term hereof from drilling a well hereunder by the order ofany constituted authority having jurisdiction, or if the Lessee shall be unable during said period to drill a well hereunder due to the equipmentnecessary in the drilling thereof not being available on account of any cause, the primary term of this Lease shall continue until one year aftersaid order is suspended and/or said equipment is available, but the Lessee shall continue to pay delay rentals in the manner herein above providedfor during such extended term.

16.Lessee, at its option, is hereby given the right and power to voluntarily pool or combine the acreage covered by this Lease, or anyportion thereof, with other lands, lease or leases in the immediate vicinity thereof, when in Lessee's judgment it is necessary or advisable to do soin order to properly develop and operate said leased premises so as to promote the conservation of oil and gas for other hydrocarbons in andunder, or that may be produced from said premises, such pooling to consist of tracts contiguous to one another and to be into a unit or units notexceeding 80 acres each in the event of an oil well, or into a unit or units not exceeding 640 acres each in the event of a gas well. Lessee shallexecute in writing and record in the county records of the county in which the land herein leased is situated, an instrument identifying anddescribing the pooled acreage. The entire acreage so pooled into a tract or unit shall be treated for all purposes except the payment of royaltieson production from the pooled unit, as if it were included in this Lease. If production is found on the pooled acreage, it shall be treated as ifproduction is had from this Lease whether the well or wells be located on the premises covered by this Lease or not. In lieu of the royalties elsewhere herein specified, the Lessor shall receive on production from a unit so pooled only such portion of the royaltystipulated herein above as the amount of his acreage placed in the unit or his royalty interest therein, on an acreage basis, bears to the totalacreage so pooled in the particular unit involved.

17.This Lease together with all its terms, conditions, stipulations and provisions shall extend to and be binding on all successorswhatsoever of said Lessor or Lessee.

IN WITNESS WHEREOF, this instrument is executed on the day and year first set out herein above,

NameSocial Security No.

This material provided courtesy of R.P.I. Institutional Services, Inc., New York, NY.

Exhibit 1-1 (3 of 3)

Mineral Deed

Know All Men By These Presents:

That

of __________________________ hereinafter called Grantor, (whether one or more) for and in consideration of (Give exact Post Office Address) the sum of_______________________ Dollars, ($_______) cash in hand paid and other good and valuableconsiderations, the receipt of which is hereby acknowledged, do ____________________, hereby grant, bargain, sell, convey, transfer, assign and deliver unto ____________________ of __________________________, (Give exact post office address) hereinafter called Grantee (whether one or more) an undivided ________________________________________ interest in and to all of the oil, gas and other minerals in and under and that may be produced from the followingdescribed lands situated in ____________________ County, State of ____________________ to-wit: containing ____________________acres, more or less, together with the right of ingress and egress at all times for the purposeof mining, drilling. exploring, operating and developing said lands for oil, gas, and other minerals, and storing, handling, transporting and marketing the same therefrom with the right to remove from said land all of Grantees property andimprovements. This sale is made subject to any rights now existing to any lessee or assigns under any valid and subsisting oil and gaslease of record heretofore executed; it being understood and agreed that said Grantee shall have, receive, and enjoy the hereingranted undivided interest in and to all bonuses, rents, royalties and other benefits which may accrue under the terms of saidlease insofar as it covers the above described land from and after the date hereof precisely as if the Grantee herein had been at thedate of the making of said lease the owner of a similar undivided interest in and to the lands described and Grantee one of thelessors therein. Grantor agrees to execute such further assurances as may be requisite for the full and complete enjoyment of the rightsherein granted and likewise agrees that Grantee herein shall have the right at any time to redeem for said Grantor by payment, any mortgage, taxes, or other liens on the above described land, upon default in payment by the Grantor, and be subrogated to therights of the holder thereof. TO HAVE AND TO HOLD The above described property and easement with all and singular the rights, privileges, appurtenances thereunto or in any wise belonging to said Grantee herein, ____________________ heirs, successors, personalrepresentatives, administrators, executors, and assigns forever, and Grantor does hereby warrant said title to Grantee____________________ heirs, executors, administrators, personal representatives, successors and assigns forever, and doeshereby agree to defend all and singular the said property unto the said Grantee herein ____________ heirs, successors, executives, personal representatives, and assigns against all and every person or persons whomsoever lawfully claiming or toclaim the same, or any part thereof. WITNESS Grantors, hand this _____ day of ______________________, 19___. This material provided courtesy of R.P.I. Institutional Services, Inc., New York, NY.

Exhibit 1-2 (1 of 10)

COPAS - 1995Kraftbilt 601-95 P.O. Box 800Recommended by the Council of Petroleum

Tulsa, OKAccountants Society

Sample

EXHIBIT

Attached and made a part of

ACCOUNTING PROCEDUREJOINT OPERATIONS

I. GENERAL PROVISIONS

1.DEFINITIONS

Joint Property shall mean the real and personal property subject to the agreement to which this Accounting Procedure is attached.

Joint Operations shall mean activities required to handle specific operating conditions and problems for the exploration, development, production, protection, maintenance, abandonment, and restoration of the Joint Property.

Joint Account shall mean the account showing the charges paid and credits received in the conduct of the Joint Operations and thatare to be shared by the Parties.

Operator shall mean the Party designated to conduct the Joint Operations.

Non-Operators shall mean the Parties to this agreement other than the Operator.

Material shall mean personal property, equipment, supplies, or consumables acquired or held for use on the Joint Property.

Controllable Material shall mean Material that at the time it is so classified in the Material Classification Manual as most recentlyrecommended by the Council of Petroleum Accountants Societies (COPAS).

Parties shall mean legal entities signatory to the agreement, or their successors or assigns, to which this Accounting Procedure isattached.

Affiliate shall mean, with respect to the Operator, any party directly or indirectly controlling, controlled by, or under common controlwith the Operator.

2.STATEMENTS AND BILLINGS

The Operator shall bill Non-Operators on or before the last day of the month for their proportionate share of the Joint Account for thepreceding month. Such bills shall be accompanied by statements that identify the authority for expenditure, lease or facility, and allcharges and credits summarized by appropriate categories of investment and expense. Controllable Material shall be summarized bymajor Material classifications. Intangible drilling costs and audit exceptions shall be separately and clearly identified.

3.ADVANCES AND PAYMENTS BY NON-OPERATORS

A.If gross expenditures for the Joint Account are expected to exceed $______ in the next succeeding month's operations, theOperator may require the Non-Operators to advance their share of the estimated cash outlay for the month's operations. Unlessotherwise provided in the agreement, any billing for such advance shall be payable within 15 days after receipt of the advancerequest or by the first day of the month for which the advance is required, whichever is later. The Operator shall adjust eachmonthly billing to reflect advances received from the Non-Operators for such month.

B.Each Non-Operator shall pay its proportion of all bills within 15 days of receipt date. If payment is not made within such time, theunpaid balance shall bear interest compounded monthly using the U.S. Treasury three-month discount rate plus 3% in effect on thefirst day of the month for each month that the payment is delinquent or the maximum contract rate permitted by the applicableusury laws in the state in which the Joint Property is located, whichever is the lesser, plus attorney's fees, court costs, and othercosts in connection with the collection of unpaid amounts. Interest shall begin accruing on the first day of the month in which thepayment was due.

4.ADJUSTMENTS

A.Payment of any such bills shall not prejudice the right of any Non-Operator to protest or question the correctness thereof; however, all bills and statements (including payout status statements) related to expenditures rendered to Non-Operators by the Operatorduring any calendar year shall conclusively be presumed to be true and correct after 24 months following the end of any suchcalendar year, unless within the said period a Non-Operator takes specific detailed written exception thereto and makes claim onthe Operator for adjustment. 1Copyright © 1995 by the Council of Petroleum Accountants Societies .

Reprinted by permission of Council of Petroleum Accountants Societies (COPAS). Copyright 1995..

Exhibit 1-2 (2 of 10)

B.All adjustments initiated by the Operator except those described in (1) through (4) below are limited to the 24-month periodfollowing the end of the calendar year in which the original charge appeared or should have appeared on the Joint Accountstatement or payout status statement. Adjustments made beyond the 24-month period are limited to the following: (1)a physical inventory of Controllable Material as provided for in Section VII(2)an offsetting entry (whether in whole or in part), which is the direct result of a specific joint interest audit exception granted bythe Operator relating to another property(3)a government/regulatory audit(4)working interest ownership adjustments

5.EXPENDITURE AUDITS

A.A Non-Operator, upon notice in writing to the Operator and other Non-Operators, shall have the right to audit the Operator'saccounts and records relating to the Joint Account for any calendar year within the 24-month period following the end of suchcalendar year; however, conducting an audit shall not extend the time for the taking of written exception to and the adjustment ofaccounts as provided for in Paragraph 4 of this Section I. Where there are two or more Non-Operators, the Non-Operators shallmake every reasonable effort to conduct a joint audit in a manner that will result in a minimum of inconvenience to the Operator. The Operator shall bear no portion of the Non-Operators' audit cost incurred under this paragraph unless agreed to by theOperator. The audits shall not be conducted more than once each year without prior approval of the Operator, except upon theresignation or removal of the Operator, and shall be made at the expense of those Non-Operators approving such audit. The leadaudit company's audit report shall be issued within 180 days after completion of the audit field work; however, the 180-day timeperiod shall not extend the 24-month requirement for taking specific detailed written exception as required in Paragraph 4.A. above. All claims shall be supported with sufficient documentation. Failure to issue the report within the prescribed time willpreclude the Non-Operator from taking exception to any charge billed within the time period audited.

A timely filed audit report or any timely submitted response thereto shall suspend the running of any applicable statute oflimitations regarding claims made in the audit report. While any audit claim is being resolved, the applicable statute of limitationswill be suspended; however, the failure to comply with the deadlines provided herein shall cause the statute to commence runningagain.

B.The Operator shall allow deny or all exceptions in writing to an audit report within 180 days after receipt of such report. Deniedexceptions should be accompanied by a substantive response. Failure to respond to an exception with substantive information ondenials within the time provided will result in the Operator paying interest on that exception, if ultimately granted, from the date ofthe audit report. The interest charged shall be calculated in the same manner as used in Section I, Paragraph 3.B.

C.The lead audit company shall reply to the Operator's response to an audit report within 90 days of receipt, and the Operator shallreply to the lead audit company's follow-up response within 90 days of receipt. If the lead audit company does not provide asubstantive response to an exception within 90 days, that unresolved audit exception will be disallowed. If the Operator does notprovide a substantive response to the lead auditor's follow-up response within 90 days, that unresolved audit exception will beallowed and credit given the Joint Account.

D.The lead audit company or Operator may call an audit resolution conference for the purpose of resolving audit issues/exceptionsthat are outstanding at least 18 months after the date of the audit report. The meeting will require one month's written notice to theOperator and all audit participants, to be held at the Operator's office or other mutually agreed upon location, and require theattendance of representatives of the Operator and each audit participant responsible for the area(s) in which the exceptions arebased and who have authority to resolve issues on behalf of their company. Any Party who fails to attend the resolutionconference shall be bound by any resolution reached at the conference. The lead audit company will coordinate theresponse/position of the Non-Operators and continue to maintain its traditional role throughout the audit resolution process.

Attendees will make good faith efforts to resolve outstanding issues, and each Party will be required to present substantiveinformation supporting its position. An audit resolution conference may be held as often as agreed to by the Parties. Issuesunresolved at one conference can be discussed at subsequent conferences until each issue is resolved.

6.AFFILIATES

Charges to the Joint Account for any services or Materials provided by an Affiliate shall not exceed average commercial rates for suchservices or Materials. Unless otherwise indicated below, Affiliates performing services or providing Materials for Joint Operations shall provide the Operatorwith written agreement to make their records relating to the work performed for the Joint Account available for audit upon request by aNon-Operator under this Accounting Procedure. These records shall include, but not be limited to, invoices, field work tickets, equipment use records, employee time reports, and payroll summaries relating to the work performed in the Joint Account. All auditswill be conducted pursuant to Section I, Paragraph 5. The Parties agree that the records relating to the work performed by Affiliates will not be made available for audit.

Exhibit 1-2 (3 of 10)

7.APPROVAL BY PARTIES

An affirmative vote of ____ or more Parties having a combined working interest of _____ percent (___%) shall be required for allitems in this Accounting Procedure requiring approval by the Parties. This vote shall be taken in writing, in a meeting, or by telephoneand the results shall be binding on all Parties. All votes must be confirmed by each Party to the Operator within two business days. The Operator shall give notice to all Parties of the results.

8.AMENDMENT OF RATES

All rates provided in Fixed Rate (Section II, Paragraph 1), Facilities (Section IV, Paragraph I), and/or Overhead (Section V, Paragraph1) shall be adjusted each year as of the first day of the production month of April following the effective date of the agreement to whichthis Accounting Procedure is attached. The adjustment shall be computed by multiplying the rate currently in use by the percentageincrease or decrease recommended by COPAS each year. The adjusted rates shall be the rates currently in use, plus or minus thecomputed adjustment. The Operator may, at intervals of at least two years, elect to review the costs associated with any fixed rate and calculate a new rate. Atintervals of at least four years, Non-Operators with 50% or more of the Non-Operators' working interest may challenge any rate subjectto this provision provided such challenge is supported by factual data. If a rate is so challenged, the Operator shall calculate a new rate. The calculation of any new rate shall be in accordance with COPAS recommendations or other procedures approved by the Parties. The new rate shall then be proposed for approval by the Parties.

II. METHOD OF CHARGES TO JOINT ACCOUNT

The Operator shall charge the Joint Account for the costs of Joint Operations in accordance with only one of the following options. The methodof charges to the Joint Account may be changed if approved by the Parties in accordance with Section I, Paragraph 7.1.FIXED RATEA fixed rate of $_______ per month per active well. Active wells are those wells that qualify for a producing overhead charge as specified in Section V, Paragraph 1.A.(3) of this procedure. The fixed rate will compensate the Operator for all costs applicable to Joint Operations except for royalties, ad valorem taxes, andproduction/severance taxes paid by the Operator for the Joint Operations and except downhole well work, Controllable Material, andall projects that qualify for drilling, construction, and/or catastrophe overhead as specified in Section V of this procedure. Theseexception costs shall be charged as specified in Sections III, IV, and V of this procedure. 2.COSTSCosts as specified in Sections III, IV, and V of this procedure.

III. COSTS INCURRED ON THE JOINT PROPERTY

The Operator shall charge the Joint Account for the following items less discounts taken, which are incurred on the Joint Property for JointOperations. Employees and contract personnel who spend substantially all their time in offices that are not Joint Property are not chargeableunder this Section while working in those offices.

1.RENTALS AND ROYALTIESLease rentals and royalties paid by the Operator.

2.LABORSalaries and wages of the Operator's employees directly employed on the Joint Property in the conduct of Joint Operations or while intransit to/from the Joint Property, provided such costs are excluded from the calculation of overhead rates in Section V. Other expenses associated with those employees to the extent the employees' salaries and wages are chargeable are also chargeable asfollows:

A.The Operator's cost of holiday, vacation, sickness, and disability benefits and other customary allowances available to allemployees, but specifically excluding severance compensation programs and all employee relocation expenses. Such costs may be charged on a when and as-needed basis or by percentage assessment on the amount of salaries and wageschargeable to the Joint Account. If percentage assessment is used, the rate shall be based on the Operator's recent cost experience.

B.Expenditures or contributions made pursuant to assessments imposed by governmental authority incurred by the Operatorassociated with salaries, wages, and benefits charged to the Joint Account.

Exhibit 1-2 (4 of 10)

C.Reimbursable travel, means, and lodging of these employees.

D.Government-mandated Training. This training charge shall include the wages, salaries, training course cost, and reimbursable travel, meals, and lodging incurredduring the training session. The cost of the training course will be limited to prevailing commercial rates.

E.The Operator's cost of established plans for employees' benefits as described in COPAS Interpretation No. 11 determined byapplying the employee benefits percent most recently published by COPAS to the chargeable salaries and wages.

3.MATERIAL

Materials purchased or furnished by the Operator for use on the Joint Property as provided under Section VI. Only such Materials shall be purchased for or transferred to the Joint Property as may be required for immediate use and are reasonablypractical and consistent with efficient and economical operations. The accumulation of surplus stocks shall be avoided.

4.TRANSPORTATION

Transportation of company labor, contract personnel, and Material necessary for the Joint Operations but subject to the followinglimitations:

A.If Material is moved to the Joint Property from the Operator's warehouse or other properties, no charge shall be made to the JointAccount for a distance greater than the distance from the nearest supply store where like Material is normally available, or railwayreceiving point nearest the Joint Property, unless agreed to by the Parties.

B.If surplus Material is moved to the Operator's warehouse or other storage point, no charge shall be made to the Joint Account for adistance greater than the distance from the nearest supply store where like Material is normally available, or railway receivingpoint nearest the Joint Property, unless agreed to by the Parties. No charge shall be made to the Joint Account for movingMaterial to other properties, unless agreed to by the Parties.

C.In the application of subparagraphs A and B above, the option to equalize or charge actual trucking costs is available when theactual charge is less than the amount most recently recommended by COPAS, excluding accessorial charges. Examples ofaccessorial charges are listed in Bulletin 21.

D.No charge shall be made for transportation costs associated with relocating employees, including the costs of moving theirhousehold goods and personal effects, unless agreed to by the parties.

5.SERVICES

The cost of contract services, equipment, and utilities provided by sources other than the Operator.

6.EQUIPMENT FURNISHED BY THE OPERATOR

A.Equipment located on the Joint Property owned by the Operator shall be charged to the Joint Account at the average prevailingcommercial rate for such equipment. If an average commercial rate is used to bill the Joint Account, the Operator shall adequatelydocument and support such rate and shall periodically review and update the rate.

B.In lieu of charges in Paragraph 6.A. above, or if a prevailing commercial rate is not available, equipment owned by the Operatorwill be charged to the Joint Account at the Operator's actual cost. Such costs may include all expenses that would be chargeablepursuant to this Section III if such equipment were jointly owned, depreciation using straight line depreciation method, interest oninvestment (less gross accumulated depreciation) not to exceed _____% per annum, and an element of the estimated cost todismantle and abandon the equipment. Charges for depreciation will no longer be allowable once the equipment has been fullydepreciated. Actual cost shall not exceed the average prevailing commercial rate.

C.When applicable for Operator-owned or -leased motor vehicles, the Operator shall use rates published by the Petroleum MotorTransport Association or such other organization recognized by COPAS as the official source of such rates. When such rates arenot available, the Operator shall comply with the provisions of Paragraph A or B above.

7.DAMAGES AND LOSSES TO JOINT PROPERTY

All costs or expenses necessary for the repair or replacement of Joint Property resulting from damages or losses incurred, except thoseresulting from the Operator's gross negligence or willful misconduct.

8.TAXES AND PERMITS

All taxes and permits of every kind and nature, including penalties and interest, assessed or levied upon or in connection with the JointProperty, or the production therefrom, and which have been paid by the Operator for the benefit of the Parties. If ad valorem taxes paid by the Operator are based in whole or in part upon separate valuations of each Party's working interest, thennotwithstanding any contrary provisions, the charges to Parties will be made in accordance with the tax value generated by each Party'sworking interest.

9.INSURANCE

Net premiums paid for insurance required to be carried for the protection of the Parties. If Joint Operations are conducted at locations where the Operator acts as self-insurer, the Operator shall charge the Joint Accountmanual rates as regulated by the state in which the Joint Property is located, or in the case of offshore operations, the adjacent state asadjusted for offshore operations by the U.S. Longshoremen and Harbor Workers (ULS&H) or Jones Act surcharge, as appropriate.

10.COMMUNICATIONS

Cost of acquiring, leasing, installing, operating, repairing, and maintaining communication systems.

11.ECOLOGICAL AND ENVIRONMENTAL

Costs of surveys as well as pollution containment actual control, and resulting responsibilities as required by applicable laws orresulting from statutory regulations.

12.ABANDONMENT AND RECLAMATION

Costs incurred for abandonment and reclamation of the Joint Property, including costs required by governmental or other regulatoryauthority.

IV. COSTS INCURRED OFF THE JOINT PROPERTY

The Operator shall charge the Joint Account for the following items, which are incurred off the Joint Property for Joint Operations.

1.FACILITIES

A.PRODUCTION-HANDLING FACILITIES

(1)ALLOCATED

The Operator shall allocate charges to the Joint Account on an equitable and consistent basis for facilities that handlesubstances extracted from or injected into the real property subject to the agreement to which this Accounting Procedure isattached if such facilities are not listed in Paragraph (2) below or covered by a separate facility agreement. Allocable chargesfor such facilities that are leased or rented shall be at the Operator's cost. All allocable charges for such facilities owned by theOperator shall be operating costs as defined in Section III incurred on the facility site plus depreciation, interest on investment(less gross accumulated depreciation) not to exceed _____% per annum, and estimated dismantling and abandonment costs. Charges for depreciation will no longer be allowable once the equipment has been fully depreciated. Such rates shall notexceed average commercial rates prevailing in the area of the Joint Property.

In lieu of charges in Paragraph 1.A.(1) above for Operator-owned facilities, the Operator may elect to charge averagecommercial rates prevailing in the immediate area of the Joint Property. If average commercial rates are used, the Operatorshall adequately document and support the rates.

(2)FIXED RATE

The Operator shall charge the Joint Account monthly for the following facilities based on the rates and units provided:

Fixed Rates

FACILITY TYPEUNITS(function performed)FIXED RATE(Well, MCF, BOE, etc.)

B.OTHER FACILITIES

The Operator shall charge the Joint Account for use of other facilities not covered by Section IV, Paragraph 1.A. (such as shorebases, field offices, telecommunications equipment, and computer equipment) as listed below or if subsequently approved by theParties. (Choose and complete only one methodology for each facility type.)

Fixed Rate Basis

FACILITYTYPE(function performed)

AVG. COM-

MERCIALRATESFIXED RATE BASISACTUAL COSTALLOCATIONUNITS

RATE(Well, MCF, BOE, etc.)

BASIS

If the Actual Cost Allocation method is chosen, all allocable charges for such facilities owned by the Operator shall be operating costsas defined in Section III incurred on the facility site plus depreciation, interest on investment (less gross accumulated depreciation) notto exceed ____% per annum, and estimated dismantling and abandonment costs. Charges for depreciation will no longer be allowableonce the equipment has been fully depreciated. Such rates shall not exceed average commercial rates prevailing in the area of the JointProperty.

2.ECOLOGICAL AND ENVIRONMENTAL

Ecological and environmental costs are those that arise from compliance with governmental or regulatory requirements or prudentoperations. These costs that are incurred off the Joint Property shall beallocated directly to the Joint Accountincluded in the Overhead rates provided in Section V

3.LEGAL EXPENSE

The Operator may not charge for services of the Operator's legal staff or fees and expense of outside attorneys unless approved by theParties in writing. Other expenses of handling, settling, or otherwise discharging litigation, claims, liens, title examinations, andcurative work necessary to protect or recover the Joint Property shall be chargeable.

4.TRAINING

Training mandated by governmental authorities for those employees who would be chargeable to the Joint Account under Section III, Paragraph 2, of this Accounting Procedure if they were not attending the training shall be chargeable to the Joint Account. Thistraining charge shall include costs as defined in Section III, Paragraph 2.D., but incurred off the Joint Property.

5.ENGINEERING, DESIGN, AND DRAFTING

Engineering, design, and drafting costs associated with major construction or catastrophes as defined in Section V, Paragraph 2, of thisAccounting Procedure, may be charged to the Joint Account only when the Operator elects to charge overhead for major construction orcatastrophes per Section V, Paragraph 2.B. Such charges shall be determined in a manner consistent with those defined in Section III, Paragraphs 2 and 5.

V. OVERHEAD

The Operator shall be compensated for costs not chargeable in Section III (Costs Incurred On the Joint Property) or Section IV (Costs IncurredOff the Joint Property) that are incurred in collection with and in support of Joint Operations.

1.OVERHEAD - DRILLING AND PRODUCING OPERATIONS

As compensation for overhead in connection with drilling and producing operations, the Operator shall charge on either aFixed Rate Basis, Paragraph 1.A., orPercentage Basis, Paragraph 1.B.

A.OVERHEAD - FIXED RATE BASIS

(1)The Operator shall charge the Joint Account at the following rates per well month: Drilling well rate per month $__________ (prorated for less than a full month) Producing well rate per month $_________

Exhibit 1-2 (7 of 10)

(2)Application of overhead - drilling well rate shall be as follows:

(a)Charges for onshore drilling wells shall begin on spud date and terminate on the date the drilling or completionequipment is released, whichever occurs later. Charges for offshore drilling wells shall begin on the date drilling orcompletion equipment arrives on location and terminate on the date the drilling or completion equipment moves offlocation or the rig is released, whichever occurs first. No charge shall be made during suspension of drilling orcompletion operations for 15 or more consecutive calendar days.

(b)Charges for wells undergoing any type of work over, recompletion, or abandonment for a period of five consecutivework days or more shall be made at the drilling well rate. Such charges shall be applied for the period from the datework over operations, with the rig or other units used in work over, commence through the date of the rig or otherunit release, except that no charges shall be made during suspension of operations for 15 or more consecutivecalendar days.

(3)Application of overhead - producing well rate shall be as follows:

(a)An active well completion for any portion of the month shall qualify for a one-well charge for the entire month. Anactive completion is one that is[1]produced,

[2]injected into for recovery or disposal, or[3]used to obtain a water supply to support production operations.

(b)Each active completion is a multi-completed well in which production is not commingled downhole shall qualify fora one-well charge providing each completion is considered a separate well by the governing regulatory authority.

(c)A one-well charge shall be made for the month in which plugging and abandonment operations are completed on anywell. This one-well charge shall be made whether or not the well has produced except when the drilling well rateapplies.

(d)All wells not meeting the criteria set forth in this Paragraph (A)(3)(a), (b), or (c) shall not qualify for a producingoverhead charge.

B.OVERHEAD - PERCENTAGE BASIS

(1)The Operator shall charge the Joint Account at the following rates:

(a)Development rate ______ percent (_____%) of the cost of development of the Joint Property exclusive of costsprovided under Section III, Paragraph 1 and Section IV, Paragraph 3; all salvage credits; the value of injectedsubstances purchased for secondary recovery; and all taxes and assessments that are levied, assessed, and paid uponthe mineral interests in and to the Joint Property.

(2)Application of overhead - percentage basis shall be as follows:

(a)Development shall include all costs in connection with[1]drilling, redrilling, plugging back, or deepening of any or all wells[2]work over operations requiring a period of five consecutive work days or more on any or all wells.

[3]preliminary expenditures necessary in preparation for drilling[4]expenditures incurred in abandoning when the well is not completed as a producer[5]original construction or installation of fixed assets, expansion of fixed assets, and any other project clearlydiscernible as a fixed asset, except major construction as defined in Section V, Paragraph 2.

(b)Operating shall include all other costs in connection with Joint Operations except that catastrophe costs shall beassessed overhead as provided in Section V, Paragraph 2.

2.OVERHEAD - MAJOR CONSTRUCTION AND CATASTROPHES

Major construction is defined as any project in excess of $_____ required for the construction and installation of fixed assets, theexpansion of fixed assets, or in the dismantling for abandonment of fixed assets as required for the development and operation of theJoint Property. Catastrophe is defined as a calamitous event bringing damage, loss, or destruction resulting from a single occurrence requiringexpenditures in excess of $_____ to restore the Joint Property to the equivalent condition that existed prior to the event causing thedamage. To compensate the Operator for overhead costs incurred in connection with major construction and catastrophes, the Operator shalleither negotiate a rate prior to beginning the work or shall charge the Joint Account for overhead based on the following rates:

A.If the Operator absorbs engineering, design, and drafting costs related to the project, the overhead assessment will be _____% oftotal project costs.

B.If the Operator charges engineering, design, and drafting costs related to the project directly to the Joint Account, the overheadassessment will be _____% of total project costs. For each project, the Operator shall provide advance notice to the Non-Operators in writing if option A above will be used forcalculating construction or catastrophe overhead. For purposes of calculating overhead, the cost of drilling and work over wells shallbe excluded and catastrophe expenditures to which these rates apply shall not be reduced by insurance recoveries. Overhead assessedunder the construction and catastrophe provisions shall be in lieu of all overhead provisions.

VI. MATERIAL PURCHASES, TRANSFERS, AND DISPOSITIONS

The Operator is responsible for Joint Account Material and shall make proper and timely charges and credits for direct purchases, transfers, anddispositions. The Operator normally provides all Material for use on the Joint Property but does not warrant the Material furnished. At theOperator's option, Material may be supplied by Non-Operators.

1.DIRECT PURCHASES

Direct purchases shall be charged to the Joint Account at the price paid by the Operator after deduction of all discounts received. Adirect purchase is determined to occur when an agreement is made between an Operator and a third party for the acquisition ofMaterials for a specific well site or location. Material provided by the Operator under vendor stocking programs, where the initial useis for a Joint Property and title of the Material does not pass from the vendor until usage, is considered a direct purchase. If Material isfound to be defective or is returned to the vendor for any other reason, credit shall be passed on to the Joint Account when adjustmentshave been received by the Operator from the manufacturer, distributor, or agent.

2.TRANSFERS

A transfer is determined to occur when the Operator furnishes Material from its storage facility or from another operated property. Additionally, the Operator has assumed liability for the storage costs and changes in value and has previously secured and held title tothe transferred Material. Similarly, the removal of Material from a Joint Property to the Operator's facility or to another operatedproperty is also considered a transfer. Material that is moved from the Joint Property to a temporary storage location pendingdisposition may remain charged to the Joint Account and is not considered a transfer.

A.PRICING

The value of Material transferred to/from the Joint Property should generally reflect the market value on the date of transfer. Transfers of new Material will be priced using one of the following new Material bases:

(1)Published prices in effect on the date of movement as adjusted by the appropriate COPAS Historical Price Multiplier (HPM) or prices provided by the COPAS Computerized Equipment Pricing System (CEPS) The HPMs and the associated date of published price to which they should be applied will be published by COPASperiodically.

(a)For oil country tubulars and line pipe, the published price shall be based upon eastern mill (Houston for special end) carload base prices effective as of the date of movement, plus transportation cost as defined in Section VI, paragraph2.B.

(b)For other Material, the published price shall be the published list price in effect at the date of movement, as listed bya supply store nearest the Joint Property or point of manufacture, plus transportation costs as defined in Section VI, Paragraph 2.B.

(2)A price quotation that reflects a current realistic acquisition cost may be obtained from a supplier/manufacturer.

(3)Historical purchase price may be used, providing it reflects a current realistic acquisition cost on the date of movement. Sufficient price documents should be available to Non-Operators for purposes of verifying Material transfer valuation.

(4)As agreed to by the Parties.

B.FREIGHT

Transportation costs should be added to the Material transfer price based on one of the following:

(1)Transportation costs for oil country tubulars and line pipe shall be calculated using the distance from eastern mill to therailway receiving point nearest the Joint Property based on the carload weight basis as recommended by COPAS in Bulletin21 and current interpretations.

(2)Transportation costs for special mill items shall be calculated from that mill's shipping point to the railway receiving pointnearest the Joint Property. For transportation costs from other than eastern mills, the 30,000-pound Specialized MotorCarriers interstate truck rate shall be used. Transportation costs for macaroni tubing shall be calculated based on theSpecialized Motor Carriers rate per weight of tubing transferred to the railway receiving point nearest the Joint Property.

(3)Transportation costs for special end tubular goods shall be calculated using the 30,000-pound Specialized Motor Carriersinterstate truck rate from Houston, Texas, to the railway receiving point nearest the Joint Property.

(4)Transportation costs for Material other than that described in Section VI, Paragraphs 2.B(1) through (3), if applicable, shall becalculated from the supply store or point of manufacture, whichever is appropriate, to the railway receiving point nearest theJoint Property.

C.CONDITION

(1)Condition A - New and unused Material in sound and serviceable condition shall be charged at one hundred percent of theprice as determined in Section VI, Paragraphs 2.A and B. Material transferred from the Joint Property that was not placed inservice on the Joint Property shall be credited as charged without gain or loss. Any unused Material that was charged to theJoint Account through a direct purchase will be credited to the Joint Account at the original cost paid. All refurbishing costsnecessary to correct handling or transportation damages and other related costs will be borne by the divesting property. TheJoint Account is responsible for Material preparation, handling, and transportation costs for new and unused material chargedto the property either through a direct purchase or transfer. Any preparation costs performed, including any internal orexternal costing and wrapping, will be credited on new Material provided these costs were not repeated for the receivingproperty.

(2)Condition B - Used material in sound and serviceable condition and suitable for reuse without reconditioning shall bepriced at the condition percentage most recently recommended by COPAS times the price determined by the pricing guidelinesin Section IV, Paragraphs 2.A and B. Any cost of reconditioning to return the Material to Condition B will be absorbed by thedivesting property.

If the Material was originally charged to the Joint Account as used material and placed in service on the Joint Property, theMaterial will be credited at the condition percentage most recently recommended by COPAS times the price as determined inSection VI, Paragraphs 2.A and B. Used Material transferred from the Joint Property that was not placed in service on the property shall be credited as chargedwithout gain or loss.

(3)Condition C - Material that is not in sound and serviceable condition and not suitable for its original function until afterreconditioning shall be priced at the condition percentage most recently recommended by COPAS times the price determinedin Section VI, Paragraphs 2.A. and B. The cost of reconditioning shall be charged to the receiving property providedCondition C value, plus cost of reconditioning, does not exceed Condition B(4)Condition D - Other Material that is no longer suitable for its original purpose but usable for some other purpose isconsidered Condition D Material. Included under Condition D is also obsolete items or Material that does not meet originalspecifications but still has value and can be used in other services as a substitute for items with different specifications. Due tothe condition or value of other used and obsolete items, it is not possible to price these items under Section VI, Paragraph 2.A. The price used should result in the Joint Account being charged or credited with the value of the service rendered or use of theMaterial. In some instances, it may be necessary or desirable to have the Material specially priced as agreed to by the parties.

(5)Condition E - Junk shall be priced at prevailing scrap value prices.

D.OTHER PRICING PROVISIONS

(1)Preparations CostsCosts incurred by the Operator in making Material serviceable including inspection, third party surveillance services, andother similar services will be charged to the Joint Account at prices reflective of the Operator's actual costs of the services. Documentation must be retained to support the cost of service. New costing and/or wrapping may be charged per Section VI, Paragraph 2.A.

(2)Loading and Unloading CostsLoading and unloading costs related to the movement of the Material to the Joint Property shall be charged in accordance withthe methods specified in COPAS Bulletin 21.

3.DISPOSITION OF SURPLUS

Surplus Material is that Material, whether new or used, that is no longer required for Joint Operations. The Operator may purchase, but shall be under no obligation to purchase, the interest of the Non-Operator in surplus Material. Dispositions for the purpose of this procedure are considered to be the relinquishment of title of the material from the Joint Property toeither a third party, a Non-Operator, or to the Operator. To avoid the accumulation of surplus Materials, the Operator should makegood faith efforts to dispose of surplus within 12 months through buy/sale agreements, trade, sale to a third party, division in-kind, orother dispositions as agreed to by the Parties. An Operator may, through a sale to an unrelated third party or entity, dispose of surplus Material having a gross sale value that is lessthan or equal to the Operator's expenditure limit as set forth in the Operating Agreement to which this Accounting Procedure is attachedwithout the prior approval of the Non-Operator. If the gross sale value exceeds the Operating Agreement expenditure limit, the disposalmust be agreed to by the Parties. The operator may dispose of Condition D and E Material under procedures normally utilized by the Operator without prior approval.

4.SPECIAL PRICING PROVISIONS

A.PREMIUM PRICING

Whenever Material is not readily replaceable due to national emergencies, strikes, or other unusual causes over which theOperator has no control, the Operator may charge the Joint Account for the required Material at the Operator's actual cost incurredin providing such Material, in making it suitable for use, and in moving it to the Joint Property providing notice in writing isfurnished to Non-Operators of the proposed charge prior to use and to billing Non-Operators for such Material. During premiumpricing periods, each Non-Operator shall have the right to furnish in kind all or part of his share of such Material suitable for useand acceptable to the Operator by so electing and notifying the Operator within ten days after receiving notice from the Operator.

B.SHOP-MADE ITEMS

Shop-made items may be priced using the value of the Material used to construct the item plus labor costs. If the Material is froma scrap or junk account, the material may be priced at either 25% of the current price as determined in Section VI, Paragraph 2.A., or scrap value, whichever is higher, plus estimated labor costs to fabricate the item.

C.MILL REJECTS

Mill rejects purchased as limited service casing or tubing shall be priced at 80% of K-55/J-55 price as determined in Section VI, Paragraphs 2.A and B. Line pipe converted to casing or tubing with casing or tubing couplings attached shall be priced as K-55/J- 55 casing or tubing at the nearest size and weight.

VII. INVENTORIES OF CONTROLLABLE MATERIAL

The Operator shall maintain records of Controllable Material charged to the Joint Account, as defined in the COPAS Material ClassificationManual, with sufficient detail to perform the physical inventories requested unless directed otherwise by the Non-Operators. Adjustments to the Joint Account by the Operator resulting from a physical inventory of jointly owned Controllable Material are limited to thesix months following the taking of the inventory. Charges and credits for overages or shortages will be valued for the Joint Account based onCondition B prices in effect on the date of physical inventory and determined in accordance with Section VI, Paragraphs 2.A. and B., unless theinventorying Parties can prove another Material condition applies.

1.DIRECTED INVENTORIES

With an interval of not less than five years, physical inventories shall be performed by the Operator upon written request of a majorityin working interests of the Non-Operators. Expenses of directed inventories will be borne by the Joint Account and may include the following:

A.Audit per diem rate for each inventory person in line with the auditor rates determined, adjusted, and published each April byCOPAS.

B.Actual travel including Operator-provided transportation and personal expenses for the inventory team.

C.Reasonable charges for report typing and processing.

The Operator is expected to exercise judgment in keeping expenses within reasonable limits. Unless otherwise agreed, costs associatedwith any post-report follow-up work in settling the inventory will be absorbed by the Non-Operator incurring such costs. Anyanticipated disproportionate costs should be discussed and agreed upon prior to commencement of the inventory. When directed inventories are performed, all Parties shall be governed by such inventory.

2.NON-DIRECTED INVENTORIES

A.OPERATOR INVENTORIES

Periodic physical inventories that are not requested by the Non-Operator may be performed by the Operator at the Operator'sdiscretion. The expenses of conducting such Operator inventories shall not be charged to the Joint Account.

B.NON-OPERATOR INVENTORIES

Any Non-Operator(s) may conduct a physical inventory at reasonable times with prior notification to the Operator. Suchinventories shall be conducted at the sole cost and risk of the participating Non-Operator(s).

C.OTHER INVENTORIES

Other physical inventories may be taken whenever there is any sale or change of interests. When possible, the selling Party shouldnotify all other owners 30 days prior to the anticipated closing date. When there is a change in Operator of the Joint Property, aninventory by the former and new Operator should be taken. The expenses of conducting such other inventories shall be charged tothe Joint Account.

DIVISION ORDERNumber 321Effective with Date of First Production

TO: LAKELAND PETROLEUM CO.

429 3rd Ave. E.

Delta, Montana 10961

This division order applies to oil, gas condensate and/or distillate or the proceeds from thesale there of produced from the following described well and land, to wit: LAKELAND PETROLEUM CO. PBY VG RV A: COLT #1 UNIT WELL, comprising 320acres, more or less, being the South Half (572) of Section 8, Township 35 North, Range 6West, Falcon County, Montana. Each of the undersigned certifies and guarantees the interest set out on Exhibit A, attachedhereto and made a part hereof, opposite the name of the undersigned is the interest owned bythe undersigned in the oil, gas, condensate and/or distillate or proceeds from the sale thereoffrom the above described property, and you will give credit for such interest shown on ExhibitA according to the following directions:

1.Until further written notice, you or your assignees, nominees or vendees are authorizedto purchase or to deliver to other purchasers for the account of the undersigned and toreceive the proceeds thereof, the oil, gas, condensate and/or distillate from the abovedescribed property.

2.For all gas taken hereunder, the undersigned will be paid the price received by LakelandPetroleum Co. for such gas, under any presently existing or any future contracts for thesale of gas, at the delivery point, less costs incurred in making delivery of such gas fromthe wellhead including, but not by way of limitation, the costs of gathering, dehydrating, compressing, treating, and transporting the gas.

3.For all oil, condensate, distillate or other liquid hydrocarbons taken hereunder, the pricetherefore shall be the same price received by Lakeland Petroleum Co. therefore at thewell, after deducting therefrom a reasonable sum to cover the costs and expenses oftreating and marketing such product. If, in order to market such products, it isnecessary to transport same by truck or barge to a marketing point, then, in that event, Lakeland Petroleum Co. is authorized to deduct from the proceeds for such productsthe trucking or barging charges. Proper deductions will be made for water, dirt, sediment, and other impurities and corrections for temperature will be made inaccordance with established rules prevailing at the time and place of delivery.

4.In the event the price received by Lakeland Petroleum Co. and paid to the undersignedfor the oil, gas, condensate and/or distillate from the above described property is inexcess of the maximum legal price that may be collected and paid, then the undersignedagrees to refund to you such excess with interest as determined under the applicableFederal or State Laws, rules, and regulations.

5.The undersigned agrees to indemnify you and hold you harmless from any liabilities forany tax imposed or assessed against the undersigned's interest hereunder and herebyauthorizes you to deduct and pay such tax or taxes.

6.If the proceeds accruing to any interest hereunder should amount to less than FiveDollars ($5.00) per month, you are hereby authorized to withhold payment until suchaccruals amount to $5.00 or to account for such proceeds on an annual basis, at yourelection.

7.Each of the undersigned warrants the title to the particular interest credited to theundersigned herein but, without impairment of such warranty, agrees that in case of anyadverse claim of title, the undersigned will furnish a bond satisfactory to you, executedby a surety company as indemnity against such claim and further agrees that you mayretain the purchase (or sales) price of the oil, gas, condensate and/or distillate withoutany obligations to pay interest thereon until such bond be furnished, or until the disputeas to ownership be settled in a manner satisfactory to you. Each of the undersignedhereby ratifies and confirms the oil and gas lease or leases and assignments and/orsubleases pertaining thereto covering the tract or tracts as to which the undersigned iscredited with an interest, and recognizes said agreements to be presently valid andsubsisting in accordance with its or their terms, and the consideration for the executionof this ratification is the proceeds from production obtained and to be obtained from theunit well.

8.The undersigned agrees to notify you in writing of any change in ownership or ofinterest and to furnish you with a certified copy of instrument evidencing such change. Any transfer, assignment or conveyance of any interest in said oil or gas shall be madesubject to this division order and effective at seven o'clock A.M. on the first day of thecalendar month following receipt of such certified copy of instrument by you.

9.You are hereby relieved of any responsibility for determining when any of the interestshown on Exhibit A shall increase, diminish, be extinguished, or revert to others as aresult of payments from said interests or as a result of the increase or decrease inproduction, and you are hereby authorized to continue to remit, pursuant to the divisionof interest set forth on Exhibit A attached hereto until you receive notice in writing to the contrary by mail addressed to you at the address shown above, together with acertified copy of the instrument evidencing such change.

10.With respect to any interest in the statement of ownership and order of division which iscredited to a married woman, the husband of such woman joins herein and becomes aparty hereto and authorizes and directs Lakeland Petroleum Co., its successors andassigns, to receive and market production under the terms hereof and to pay the valuethereof to his wife in the proportion set forth on Exhibit A, which such payment shallbe in full and complete discharge of all obligations hereunder, in the same manner asthough such payment had been made directly to him or to him and his wife jointly. Eachinterest owner warrants and represents that his or her marital status has remainedconstant subsequent to his or her acquisition of interest in the lands described.

11.Each owner of a working interest in the land described above warrants that the royaltiesor overriding royalties applicable to the working interest owned by such owner arecorrectly set out and owned as shown on this division order. Each such owner of aworking interest hereby authorizes and directs you to make payment for all royalties oroverriding royalties that may become due and attributable to the working interest of theundersigned in accordance with this division order. Each such owner of a workinginterest in said land agrees that you will be free of any liability for payment made inaccordance with this division order.

12.This division order shall be effective as to each party signing same irrespective ofwhether or not any other party whose name appears in Exhibit A attached heretoexecutes this instrument or any other instrument of similar import.

13.This division order shall insure to the benefit of Lakeland Petroleum Co. and theundersigned, their heirs, successors, and assigns; and, the undersigned, and each ofthem, by executing this division order, hereby agree that the persons, partnerships, corporations, or firms to whom you may sell or market all, or any part, of theproduction produced from or allocated to the lands described above may make paymentto you for all such production purchased from the undersigned; that they will look solely to you for payment of their interest in such production which is being purchased fromthem hereunder; and that, insofar as concerns and to the extent of their interest ownedhereunder, that they will hold harmless, protect and indemnify all purchasers from youagainst any and all claims, damages, and expenses of whatsoever nature in connectionwith the purchase of such production by said purchaser and the payment to you forsame.

Signature of Owner, Date and Address

WITNESSES:SIGNATURE OF OWNER:DATE:

ATTEST:CASPER DEVELOPMENT INC.

ADDRESS: 300 Sixth StreetCitation, TX 80853EMPLOYER IDENTIFICATION: 32-1234567WITNESSES:SIGNATURE OF OWNER:DATE:

ATTEST:CASPER DEVELOPMENT INC.

ADDRESS:

FPC - Colt #1 Monte Carlo FieldFalcon County, MontanaEXHIBIT A

OWNER NAME AND ADDRESSDECIMAL INTERESTHelen Mary Allen, First Street, Delta, Montana 10456.03668162 RI

Charles Gary Bates, 426 Ada, Courier, Montana 10455.00156666 RI

Mary Joyce Cottey, 65631 Fifth Ave. N.Y. City 00010.00013682 RI

Delta Industrial Development Corporation, Incorp.

426 3rd Ave. W. Delta, Montana 10456.01563219 RI

Jack C. Coker, Jr., Second St., Delta, Montana 10454.02368542 RI

Roger P. Tyler, Jr., Third St., Gran Prairie, TX 70855.05425169 RI

Charles G. Regis, Fourth St., Delta, Montana 10454.00443594 ORRIKatherine C. Hood, Fifth St,, Delta, Montana 10456.02752420 ORRIMartha B. Mills, 346 Scott, Delta, Montana 10456.01240234 ORRICasper Development Inc.

Sixth Street, Citation, TX 80853.06218417 ORRIJack C. Elon, Seventh St., Delta, Montana 10454.03430456 ORRIRoger P. Coker, 4236 Vance, Gran Prairie, TX 70855.00295729 ORRIHorace A. Keene, Eighth Street, Delta, Montana 10455.04936223 WI

Frank K. Loras, Ninth Street, Delta, Montana 10455.62368091 WI

Jake Marin, Tenth Street, Gran Prairie, TX 70855.04231047 WI

Suspense.00888349

TOTAL 1.00000000

Note:The interests of Jasper and Katherine C. Hood have the option to convert to a WIafter payout. If payout occurs, additional calculations will be necessary.

Division of Interest Breakdown

Division of Interest Breakdown

DIVISION OF INTEREST BREAKDOWN ** K10 **

FOR PROPERTYDATE JANUARY 29, 1983 ERYAV122 PAGE 001LEASE NUMBER BACKBASE WL Z PROD DISB RUN LEASE NAME00640 04 0 1 7 J. XYZ SO ALV CAD WFT A/C OWNER P PART MISC OWNER NAME SUSP REFERENCE DECIMAL REVERTING EFF.

/ NO. / CODE PROD CODE OF INTEREST DATEI P PMT INTEREST1 521 62000 0 A OWNER G2102204 .8193711 10812 521 14314 0 B OWNER G7110119 .07617192 521 15859 0 C OWNER G1040606 .07617193 521 44257 0 D OWNER G7110119 .01271483 521 57891 0 E OWNER G7110119 .01271483 521 59237 0 F OWNER G2102204 .0028555 1081

1.0000000 .00000001-33

Chapter 2OIL AND GAS INDUSTRY ISSUES

ISSUES RELATED TO AN OIL AND GAS ENTITY AND ACTIVITY -- OVERVIEW

When an examining officer receives a tax return that is in the business of oil and gasor has related oil and gas business activities, one needs to scrutinize the returncarefully to determine its potential for examination. There are many different areasthat could generate an issue or issues that need to be looked at during theexamination. This section of the MSSP audit techniques guide discusses specificareas that are typical to an oil and gas entity or activity and audit techniques that canbe of use to ensure proper coverage of the specific areas. North Texas District conducted audits on activity codes 219 and 215 corporationsrelated to the oil and gas industry. It was discovered that some items whichappeared productive on the face of the return were in fact not productive for thisindustry. However, items that appeared reasonable upon the first inspection of thetax return were in fact productive.

Unproductive Issues

Cost of goods sold on oil and gas working interest returns commonly runs 80 to 90percent of gross receipts. The great majority of the cost is lease operating expenses(LOE), a catch-all classification for all direct costs connected with running aproductive oil and gas well. It was discovered that LOE was virtually unproductivein our examinations. Other major components of cost of goods sold, IDC and dryhole costs were more productive. The oil and gas industry is highly capital-intensive. This is due to the enormouscost of developing properties and the low probability of success. Consequently, retained earnings of oil and gas companies are frequently in the tens of millions ofdollars. Retained earnings was found to be unproductive. The taxpayers, as ageneral rule, maintained detailed plans for acquisition and development of propertieswhich would cost in the tens of millions and upwards to the hundreds of millions ofdollars.

Productive Issues

Geological and geophysical (G & G) costs are frequently expensed on all properties, whether they were leased or not. If the taxpayer has acquired part or all of the areassurveyed, the G & G expenses are part of the leasehold cost. They are part of the basis for cost depletion and for computing gain or loss at the date of disposition, butthey are not a current expense. Depletion includes cost depletion as well as percentage depletion. One should securea detailed depletion schedule to determine which properties have percentage depletionrather than cost. Also determine how close the cost depletion available is to thepercentage depletion. Your adjustment will probably only be the difference betweencost depletion and percentage depletion. To examine cost depletion, the services of apetroleum engineer is required. The engineer will evaluate the reserve computation. However, one should take caution if an adjustment is made to percentage depletion.

Regular income tax will be increased but alternative minimum tax could be affected, ifapplicable, through the depletion tax preference. The alternative minimum taxpreference item for excess depletion was repealed by the Energy Policy Act of 1992for taxable years beginning after December 31, 1992, for independent producers. Thus, examining officers should not be concerned with the effect of making anadjustment to percentage depletion on alternative minimum tax after the calendar yearof 1992. However, the issue is still viable in a fiscal year that straddles 1992 and1993. Percentage depletion can be a very productive issue, particularly when the taxpayerhas obtained proven property with low basis. Overhead allocation for depletion canproduce major changes to the 50 percent of net income per property limitation. Thetaxpayer is required to be consistent in allocating overhead, and to have a reasonablebasis for the allocation of costs. If a change in percentage depletion would have amaterial effect on the tax liability, the methods used by the taxpayer in allocatingoverhead should be scrutinized. IRC section 29 provides a tax credit for the production of fuel from nonconventionalsources. The Revenue Reconciliation Act of 1990 redesignated old IRC section29(b)(5) as section 29(b)(6) and added new IRC section 29(b)(5). The new sectionmodified the energy incentive credit. This modification is covered in depth in the audittechniques handbook, IRM 4232.8:800. If this issue is encountered in the course of anexamination, PIP should be contacted. Also, examiners should make a referral to theEngineering program utilizing the services of an engineer.

Unique Issues

Alternative Minimum Tax -- Excess Depletion Preference

In Hill v. United States, 21 Cl. Ct. 713 (1990), the court held that adjusteds basisreferred to in IRC section 57(a)(8) -- currently IRC section 57(a)(1) -- includesunrecovered depreciable tangible costs. As a result, taxpayers filed claims for refundsincreasing the adjusted basis in the property when computing the excess percentagedepletion to be reported as a tax preference item subject to alternative minimum tax.

The Supreme Court, reversing the lower court, held in United States v. Hill, 113 S.Ct. 941 (1993), that the adjusted basis does not include depreciable drilling anddevelopment costs in mineral deposits for determining the tax preference item ofdepletion for alternative minimum tax purposes. This decision was rendered onJanuary 25, 1993, during the filing season for 1992 income tax returns. Even though the issue dies out on 1991 claims or original returns, examining officersshould pay particular attention to the adjusted basis of property for alternativeminimum tax purposes in 1992. Even though taxpayers are not computing excessdepletion in accordance with the Hill decision, they may not have adjusted the basisback to the amount of basis computed without reference to Hill. This issue will not be of concern after 1992. The Energy Policy Act of 1992eliminated the excess depletion as an alternative minimum tax preference item. Thechange in law applies to independent producers and royalty owners, not integrated oilcompanies, and is effective for taxable years beginning after December 31, 1992.

Intangible Drilling Costs Preference - Tax Benefit Rule

The preference for IDC equals the amount by which excess IDC for the tax yearexceeds 65 percent of the net income from oil and gas properties for that year. Netincome from oil and gas properties is the excess of the aggregate amount of grossincome, within the meaning of IRC section 613(a), from all oil and gas properties ofthe taxpayer received or accrued by the taxpayer during the tax year, over the amountof any deductions allocable to such properties (including percentage depletion) reduced by the excess IDC.

One oil and gas publication, Income Taxation of Natural Resources 1992, C.W. Russell, takes the position that the tax benefit rule under IRC section 59(g) can beapplied in instances where a taxpayer is subject to both the IDC preference and thedepletion preference. According to Russell, the rule applies because each dollar ofdepletion preference generates two dollars of preferences because the depletion alsodecreases net income from oil and gas. See Exhibit 2-2 for an illustration of how the tax benefit rule applies in this situation. There is no published position on this situation at this time. If an examining officerencounters this issue, technical advice should be requested. This potential issue will not be of concern with regard to independent producers androyalty owners after 1992. The Energy Policy Act of 1992 repealed the alternativeminimum tax IDC preference item for independent producers and royalty owners, notintegrated oil companies. The repeal is effective for taxable years beginning afterDecember 31, 1992.

Uniform Capitalization Rules

Final regulations were adopted in August 1993 (TD 8482, August 6, 1993). The finalregulations made several changes to the temporary regulations but still leave someissues unresolved. Still some in the oil and gas industry advocates that the uniformcapitalization rules of IRC section 263A do not offer sufficient guidance as to theapplication of the rules to the oil and gas industry.

Capitalization of Delay Rentals

It is the position of the industry that delay rentals are pre-production period costswhich were not intended to be affected by IRC section 263A. This issue is notspecifically addressed in any regulations or IRS notices. Prior to the effective date of the final regulations, the Service's position was that delayrentals should be capitalized as an indirect expense incurred in improving ordeveloping an oil and gas leasehold, citing Temp. Treas. Reg. section 1.263A- 1T(b)(2)(iii). Pre-production costs are addressed in the final regulations, Treas. Reg. section 1.263A-2(a)(3)(ii). However, neither the temporary nor final regulationsspecifically address delay rentals because guidelines for specific industries are notincluded in them. Thus, if an examiner has a delay rental issue, PIP should beconsulted and technical advice should be requested.

Capitalization of Interest Expense

The final regulations under section 1.263A(f), as a general rule, require owners of oiland gas properties to capitalize any interest expense associated with the production ofdesignated property as defined in the regulations. The interest expense to becapitalized is that which is incurred during the production period that could have beenavoided if the production expenditures had been used to repay or reduce the owner'soutstanding indebtedness. This method is referred to as the avoided cost method. Itassumes that debt of the owner would have been repaid or reduced if the productionexpenditures had not been incurred, without regard to the owner's actual subjectiveintentions or to restrictions against repayment or use of the debt proceeds. The industry has raised concerns over the definition of real property for the interestrules. The final regulations define real property as including permanent structureswhich include foundations, oil and gas pipelines, derricks, and storage equipment.

Assistance in IRC Section 263A

If one encounters a uniform capitalization issue with regard to the oil and gas industry, one of the following should be considered:

1.Consult the PIP team in Midstates Region to determine if there is an ISP issue onyour concern.

2.Request technical assistance through the technical section of QualityMeasurement Staff or the staff that directs technical assistance to DistrictCounsel.

3.Request technical advice from National Office.

General Issues (Non-Oil and Gas)

Due to hard times in the oil and gas industry, bad debts and liquidations of subsidiarieshave become common. These two areas, bad debts from subsidiaries and worthlessstock of subsidiaries, have been very productive issues. When a controlled group filesa consolidated return, they are generally barred from claiming any losses ontransactions within the related group even if the subsidiary is liquidated, or theproperty is disposed of outside the group. Treas. Reg. section 1.1502-20 generallydisallows a deduction for any loss recognized by a member of a consolidated groupwith respect to the disposition of the stock of a subsidiary. Unrecognized income from forgiveness of indebtedness of a subsidiary has beenproductive when the taxpayers have property related to the forgiven debt and have notadjusted the tax attributes of the property in computing the gain or loss. Generally, they excluded the income from the forgiveness and then claimed a loss or reported alesser gain than they should have on the disposition. They are usually entitled to theexclusion, but they are required to reduce their NOL carryover, or the basis of theproperty, or other tax attributes.

TAXPAYERS SUBJECT TO BOTHDEPLETION PREFERENCEANDIDC PREFERENCE

COMPARISON OF TAX PREFERENCE CALCULATION:

Net Oil and Gas Income(1)(2)

$146,643$146,643Add: Depletion Preference N/A$32,990Adjusted Net Oil and Gas Income$146,643$179,633Excess IDC$261,092$261,092Less: 65 Percent of Net Oil and Gas Income

IDC Preference$95,318$165,774$116,761$144,330

1.Net income from oil and gas properties computed according to IRC section 57(a)(2)(C). The excessintangible drilling costs tax preference is according to IRC section 57(a)(2)(A) and (B). No tax benefitreduction is allowed under IRC section 59(g) in this calculation.

2.Net income from oil and gas properties computed according to IRC section 57(a)(2)(C), but it is adjustedto give effect to a purported tax benefit. The so called tax benefit calculation is based on aninterpretation of IRC section 59(g).

EXAMINATION OF AN OIL AND GAS ENTITY AND ACTIVITY

Once an examiner receives a tax return for examination, a precontact analysis of thereturn should be conducted. Below are some suggestions that are applicable to oil andgas returns when preplanning an examination. Analyze the M-1 carefully for the book to tax return differences. The following itemscan usually be found relating to an operator: percentage depletion; impairment ofunproven properties; abandonments; and intangible drilling costs (IDC). Differences indepreciation and timing issues are similar to those in other industries. Analyze the detailed depletion schedule for cost depletion versus percentage depletion, and ratio of expenses to income on each property. Decide whether there is anypotential in examining percentage depletion. It you are going to examine it, decidewhich properties you will examine; it is not an all or nothing proposition. A sample ofthe universe of depletable properties is usually selected for examination. Inspect Other Deductions carefully. This is usually where you'll find such items asgeological and geophysical (G & G) expenses, professional fees, and consultants. Accounts of this nature should be examined, if they are material in amount, for capitalexpenditures treated as current expenses. The balance sheet should be analyzed for changes in depreciable and depletable assets. They can indicate acquisitions and/or dispositions of properties. Also analyze thedepreciation schedule, Schedule D, and Form 4797 for confirmation of the changes. Loans to and from shareholders reflected on the balance sheet should be scrutinizedclosely. This can lead you to capital contributions being treated as a loan to qualify fortax-free return of capital to the shareholder and an interest deduction to the company, or to forgiveness of indebtedness to the shareholder. Scrutinize the eliminationscolumn of the consolidated balance sheet for loans within the consolidated group. Treating capital investment in subsidiaries as loans seems to be fairly common inmedium to large sized companies.

Engineering Referral

Examiners should determine as early as possible in the audit if the assistance of anengineer is needed. Engineering referrals are not mandatory in all cases. An engineercan still be used to assist in the examination even though a case does not meet themandatory referral criteria.

District or regional directives and Internal Revenue Manual 42(16)0 should beconsulted for information on the engineering program and assistance that is availableto revenue agents. For example, North Texas District examining officers shouldconsult Regional Commissioner Memorandum 42-24, Rev. 5, Engineering Program, dated May 4, 1984.

There are certain cases that meet the criteria for a mandatory referral to theengineering program. Internal Revenue Manual section 42(16)2.2 sets out the types ofreturns that are mandatory referrals. They are the following:

1.All corporate returns, including Form 1120S, with assets of $10,000,000 andover. Returns of banks, trust companies, insurance carriers or agents, creditagencies, and security brokers are excluded and ordinarily will not be referred forengineering assistance.

2.All partnerships and joint venture returns with annual gross receipts or totaldeductions of $1,000,000 and over.

3.All returns with a fair market value issue of $500,000 and over.

INITIAL INTERVIEW QUESTIONS

The following questions are suggested additions to normal initial interview questionsfor any income tax examination. They should be adapted to the particularcircumstances of the taxpayer under examination. Have there been any assignments of income (royalties, production payments, etc.)? If so, to whom and for what purpose?

Are you an operator, working interest holder, royalty interest holder, or acombination of these (that is, operator and working interest holder)?

If you are an operator, how is your fee computed and were you audited by anygovernmental (federal or state) regulatory agency?

If you are not the operator, who is the operator of each property? What recordsdo you get from the operator?

Are contracts with leaseholders and operators, etc. available? If not, when willthey be?

Are the division orders for your well participations available?

Are you responsible for preparing or filing any state regulatory reports? Forexample, reports are filed in the State of Texas with the Texas RailroadCommission. (See Exhibits 3-1, for descriptions of forms required to be filed with the State of Texas.) The types of reports required to be filed with other statesmay differ. The state regulatory agency needs to be consulted.

Have any audits been performed on any of the operators by the joint interestholders?

Do you capitalize or expense IDC? Have there been any changes in yourtreatment of IDC since the inception of your business?

Did you buy or sell any leases, or make any other conveyances during this year?

If there was a sale, did you recapture IDC? Did you enter into any sharingagreements, such as poolings or unitizations?

How did you compute depletion on the return?

Are there any carry-overs of depletion?

Did you receive or pay for any test well contributions this year (that is, dry hole orbottom hole contributions)?

Is there any coding within your accounting system that identifies operatedworking interest properties from non-operated properties?

For financial purposes do you periodically evaluate your unimproved properties todetermine whether they have been impaired (partially worthless)? If so, how doyou account for impaired leases?

How are you allocating overhead expenses among properties for the percentagedepletion limitation computation (that is, gross income, direct expenses, etc.)?

Was the income from each property reduced by the bonus exclusion for thepercentage depletion computation?

If you are the operator, do you have an in-house geologist or engineers thatprovide you information and data to develop properties or purchase alreadyproducing properties?

INITIAL INFORMATION DOCUMENT REQUEST

Certain records are necessary to begin an examination of an oil and gas activity. Theseshould be requested in the first Information Document Request (IDR), Form 4564, sent to the taxpayer. Also, the taxpayer should be requested to be present at the verybeginning of the audit.

The following list of items, which should be requested on the initial IDR, cover onlyoil and gas issues. Not all items will fit all taxpayers and should be adjusted to fit theparticular taxpayer under examination. The basic records needed are as follows:

1.Charts of cost centers, lease names, and numbers.

2.Detailed depletion schedules related to the tax return.

3.For leaseholds abandoned during this tax year, records to show the expiration orrelease of the lease.

The following should also be identified in the initial IDR. This information should berequested to be made available, within a reasonable time period, for specific propertieswhich will be identified later:

1.Joint venture/operator agreements in effect during 19___.

2.Reports of any joint interest or operator audits.

3.Copies of division orders.

4.Whether or not you are the operator on all properties, operator's reports (jointinterest billings), and Authorization for Expenditures (AFEs).

5.Plug and abandonment reports for dry holes claimed for 19___.

ACCOUNTING METHODS

Before probing into specific accounts and items, ascertain what accounting method thetaxpayer is using. Below are some suggested questions and audit techniques for use inmaking this determination.

1.Ask the taxpayer what method of accounting they use for financial purposes. Isthe method successful efforts (SE) or full cost (FC) and cash or accrual?

3

2.Obtain the adjusting entries which convert book and financial income to taxableincome.

3.Look for M-1 adjustments in the following areas:

a.SE Method1)Items deducted on the books as an expense that should not beincluded on the tax return:

a)Impairments.

b)Dry-hole and bottom-hole contributions.

2)Items deducted on the tax return that should not be included on thebooks as an expense:

a)IDC.

b)Dry holes [developmental wells].

3)Items deducted as an expense on both the books and the return, butthe amounts may vary:

a)G & G costs.

b)Depletion.

c)Abandonments.

d)Depreciation.

b.FC Method1)All items deducted as expenses on the books are the same on the taxreturn.

2)Items deducted on the tax return that should not be included on thebooks as an expense:

a)IDC.

b)Dry holes [developmental wells].

c)G & G costs.

3)Items deducted as expense on both the books and the return, but theamounts may vary:

a)Depletion.

b)Depreciation.

PROPERTY DEFINITION

The definition of property was previously discussed Chapter 1 in the section entitledGeneral Description of the Industry. Below are audit steps that should be followed only if the examiner determines that a material distortion in the property definition islikely.

1.Ask the taxpayer what definition they use for property in computing depletion(that is, well, prospect, lease, etc.).

2.Compare this definition to the IRS definition, set out in IRC section 614, todetermine if a material distortion has occurred. If the taxpayer states that it usesthe well or prospect, it has an incorrect property definition for income taxpurposes.

3.Request copies of the taxpayer's depletion schedules for the current, prior, andsubsequent years. If the taxpayer has the well account numbers on the schedules, compare the groupings of these account numbers between years to see if thetaxpayer is changing the property definition each year to obtain the bestdeduction.

4.If you wish to test some properties to determine whether the definition has beencomplied with, the following steps should be followed:

a.Select a sample of properties.

b.Request the lease file on each property.

c.Review the lease and determine what tracts make up the lease and whattypes of interest were owned on each lease.

d.Have the taxpayer provide you with a map or plat that outlines the tractsthat make up the property as it was used for claiming deductions on the taxreturn.

e.Compare the taxpayer's definition to the IRS definition of property.

1)Each different type of interest (working interest, royalty interest, etc.) is treated as a separate property.

2)The tracts or parcels of land must be contiguous (that is, having acommon side) and acquired from the same person on the same day. See the illustration in Chapter 1.3)Separate oil and gas deposits on each tract will be treated as oneproperty, unless an election is made to treat them as separateproperties. To qualify for separate property treatment, the taxpayermust account for the production from each deposit separately.

f.If an incorrect definition was used by the taxpayer, determine whether aclear and convincing basis exists to make the change.

1)If there is not a clear and convincing basis, the property definition willbe accepted as established by the taxpayer pursuant to Rev. Proc. 64- 23, 1964-1 (Part 1) C.B. 689.2)If a clear and convincing basis exists occurred, correct the deductionclaimed using the correct property definition. Increase the samplesize to correct the property definition on any properties that wouldcause a material distortion of the tax deduction in question.

Unitization

1.Ask the taxpayer if any new unitizations or pooling agreements were entered intoduring the year under audit.

a.If so, ask the taxpayer if any payments were to be paid or received asequalization payments.

b.If payments were made or received, determine if the taxpayer handled themcorrectly.

2.Compare the depletion computation for the prior and subsequent years with theyear under examination. The addition of a property with the word unit in itsname might indicate a current unitization. The deletion of one or more properties, which appeared to be making a profit, and the addition of another might indicatecurrent unitization.

3.Check unitized properties for matching of income and expenses. The taxpayermay shift the expenses from a producing property to a nonproducing or marginalproperty. Legal expenses incurred relating to the formation of a unit have beenheld as a deductible expense in Fields v. Commissioner, 229 F.2d 197 (5th Cir. 1956), 48 A.F.T.R. 859, 56-1 U.S.T.C. 54,470. However, it has recently beenheld in INDOPCO, Inc. v. Commissioner, 112 S. Ct. 1039 (1992), that legalexpenses incurred by a target corporation in a friendly takeover werenondeductible capital expenditures.

a.Request the lease file on each property.

b.Review the lease and determine what tracts make up the lease and whattypes of interest were owned on each lease.

c.Obtain from the taxpayer a map or plat that outlines the tracts that make upthe property as it was used for claiming deductions on the tax return.

d.Compare the taxpayer's definition to the IRS definition of property.

1)Each different type of interest (working interest, royalty interest, etc.)is treated as a separate property.

2)The tracts or parcels of land must be contiguous (that is having acommon side) and acquired from the same person on the same day.

3)Separate oil and gas deposits on each tract will be treated as oneproperty, unless an election is made to treat them as separateproperties. To qualify for separate property treatment, the taxpayermust account for the production from each deposit separately.

e.If an incorrect definition was used by the taxpayer, determine whether aclear and convincing basis exists to make the change.

1)If there is not a clear and convincing basis, the property definition willbe accepted as established by the taxpayer pursuant to Rev. Proc. 64- 23, 1964-1 (Part 1) C.B. 689.2)If a clear and convincing basis exists occurred, correct the deductionclaimed using the correct property definition. Increase the samplesize to correct the property definition on any properties that wouldcause a material distortion of the tax deduction in question.

AREAS TYPICAL OF AN OIL AND GAS ENTITY

Gross Income

Entities in the oil and gas industry receive gross income from various sources. Belowis a discussion of the various sources and suggested audit techniques to use whenperforming an income probe.

Oil and Gas Sales

When a well becomes productive, the operator of the well enters into a contract to sellthe oil and gas, and a division order is created. The division order describes theeconomic interest, the owners of a property and the types of interest owned. (Exhibit1-3 in Chapter 1 provides an example of a division order.) The division orderaccounts for 100 percent of the revenue ownership of the property. The purchaseruses the division order as the basis for paying revenues to the economic interestowners after paying the applicable severance taxes. The interests in the division orderare stated in decimals. The division order may direct the purchaser to pay all of theinterest holders directly, but usually it directs the purchaser to pay only the royaltyowners directly and remit the receipts payable to the working interest holders to theoperator. Purchasers of gas usually will remit 100 percent of the proceeds, lessseverance taxes, to the operator. The operator prefers to distribute the receipts to theworking interest holders ensuring that other working interest owners pay their share ofthe well operation costs. The operator's payments to the other working interestholders are also based on the division order. Secure a copy of the division order and

Disappearance of a Particular Property

Examiners should compare the royalties reported by property for the current year withthe prior and subsequent years. If they are not clearly identifiable on the return, copiesof the depletion schedules should be requested. If a particular property disappears, orits income is reduced substantially, the taxpayer might have assigned his or her interest to a bank or third party as payment on a loan. Question the taxpayer about this andinspect new loan agreements; one can see how the repayment is structured. Ifproduction from a well is substantially reduced there may be correspondence betweenthe operator and the royalty owner, which would explain the reduction.

Working Interest Owner

Below are suggested audit techniques with regard to conducting an income probe on aworking interest owner. lease to compare the ownership percentages designated to the taxpayer with thepercentage interest used to calculate the amount actually paid per the remittance slip. Gross revenue from oil sales is determined by multiplying the barrels of oil deliveredby the price per barrel of the particular grade of oil. The price of the oil may be theposted field price (price published and circulated between buyers and sellers in aparticular field) or a spot price (short term negotiated price between buyer and seller). The oil produced from a well usually is held in a tank battery waiting for sale. Whenenough oil is accumulated, it is sold. It can be transported from the property by truckor pipeline. A run ticket is prepared at the point of transfer which records the gravity, temperature, impurities, and quantity of oil delivered. The amount of payment for theoil is based upon information contained in the run ticket. It is a reliable third partysource document for verifying the volume of oil leaving the property. (A sample of arun ticket can be obtained from the Council of Petroleum Accountants Societies(COPAS), Arlington, Texas.) Gross revenue from gas sales is determined by multiplying the cubic feet sold, according to the gas settlement statement, by the contract price. Natural gas isgathered through a pipeline system; it is not stored on the leased property prior to sale. Meters are put on the line to measure the amount of gas removed from a well orproperty. Gas is measured in cubic feet (CF) and is usually stated in MCF (thousandsof cubic feet) or MMCF (millions of cubic feet). Oil and gas from the lease are sometimes used on the property for lease operations (forexample, oil may be spread on lease roads, oil and gas may be burned as boiler orgenerator fuel, or gas may be used for gas injection or lift). If the oil or gas is used forlease operations, it should not be included in gross income. If it is used on an adjacentlease or used for the lessor's personal use, then it should be included in the grossincome of the property.

1.Compare the properties per the detailed depletion schedules for the current yearwith the prior and subsequent years. Look for properties that:

a.Continue to operate at a loss and no drilling or development is being done;

b.Report income out of line with the expenses being claimed;

c.Disappear from one year to the next, but no sale of the property is reported; and/ord.Incur large amounts of IDC but just before production the property istransferred to a third party or other family member.

2.In items 1. a, b, or c above, the taxpayer may be paying expenses of anotherinterest owner or may have assigned a portion of the revenue interest to a thirdparty for payment on a loan, etc. if questions arise under these items above, areallocation of income and expenses under IRC section 482 should be considered.

The following additional audit steps are recommended:

a.Inspect the division order to determine the interest the taxpayer shouldreceive. Compare this to the joint interest billings or remit slips. Theinterest that the taxpayer actually received should be reconciled to theinterest reported.

b.Inspect the lease agreement and amendments, if any, to determine thetaxpayer's interest in the expenses. Compare this interest to the amountallocated on the joint interest billings and the amount claimed as a deductionon the return.

c.Inspect the lease file to determine if there is any special problem with theproperty. There may be letters, or other correspondence, detailingproblems on the property which would confirm any explanations made bythe taxpayer.

d.Obtain Securities and Exchange Commission's Form 10-K, if required to befiled. Form 10-K should disclose production payments and their nature.

e.Inquire if a joint interest audit has been performed. If so, request results ofthe audit.

Lease Bonus

A bonus is paid for the execution of an oil and gas lease and is regarded as ordinaryincome to the lessor. It is usually computed on a per-acre basis. Inspect a copy of thelease agreement to determine the terms of the payments. If the lease agreementspecifies that certain annual payments are to be made for a fixed number of years regardless of production, they are not recouped from future production. It is notimportant to establish that the payments were in fact a lease bonus. Prior to the TaxReform Act of 1986, there was a question as to whether percentage depletion wasallowable on lease bonuses. IRC section 613A(d)(5), as amended by the Tax ReformAct of 1986, clarified this controversy. The amendment provides that bonuses, advance royalties and similar items received or accrued after August 16, 1986, intaxable years ending after that date are not eligible for percentage depletion. If the lessee is unable to avoid such payments by production or by terminating thelease, then the annual payments are regarded as an installment lease bonus. Paymentsreceived from an obligation that is not salable or freely transferable are income in theyears the payments are received. However, if the rights to the bonus payments arefreely transferable and readily salable, the total amount of the lease bonus is includiblein income at the time the lease is executed even though the bonus is payable ininstallments. (Rev. Rul. 68-606, 1968-2 C.B. 42.) Examining officers should inspect a copy of the check or checks received to verify theamount of the lease bonus payment. Reconcile the checks to the lease agreement.

Delay Rentals

Delay rentals are amounts paid to the lessor for the privilege of deferring thecommencement of a well on the lease. Delay rentals are reportable by the lessor asordinary income. Since they are in the nature of rent, the payments for delay rentalsare not subject to depletion. Inspect a copy of the lease agreement. The statedamount reflected in the lease should be compared to the amount received by thetaxpayer. If it is different, ask the taxpayer why the amounts do not agree. If asmaller amount was paid, an amendment to the lease was probably made to keep thelease in force. Secure a copy of the amendment and inspect it. For discussion of the capitalization of delay rentals, see Chapter 2.

Royalty Income

A royalty interest entitles the owner to a specific fraction (in kind or in value) of thetotal production of oil and gas free of development and operating expenses. The leaseagreement specifies the royalty retained by the landowner. Examiners should alsoinspect the check stubs and remittance slips to verify the amount of royalty received. Royalty income is ordinary income to the lessor.

Advance Royalties

Advance royalties result from lease provisions that require the operating interestowner to pay a specified royalty regardless of whether any oil or gas is extracted during the period. The specified royalty is a fixed amount or an amount based onroyalties due at a specified production level. Advance royalties are reportable asordinary income.

Minimum Royalties

Advanced royalties that result from a minimum royalty provision may, at the option ofthe payor, be deducted in the year paid or accrued. A minimum royalty provisionrequires 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 ofmineral production requiring payment of aggregate royalties in a greater amount. Forleases entered into prior to October 29, 1976, the option to deduct in the year paid oraccrued was available for all advanced royalties. The option, however, is a one timeelection for the taxpayer. Once it is chosen, the election cannot be changed.

Shut in Royalties

Most lease documents provide for payments to be made to the royalty owners when awell is shut in. A well is shut in when it is turned off because of lack of market ormarketing facilities. Shut in royalties are paid to the lessor when the well, which iscapable of producing in commercial quantities, is shut in. The lessee is entitled todeduct the shut in royalty payment and the lessor must take the payment into income.

Production Payments

A production payment is a right to oil, gas, or other minerals in place that entitles itsowner to a specified fraction of production until a specified amount of money or minerals has been received. For example, a typical production payment might requirethat 80 percent of production be paid to the holder until $50,000 plus 11 percentinterest is received. A production payment is payable only out of the workinginterests' share of production. There are two basic types of production payments. The first is a retained productionpayment. This is created when an owner of an interest in a mineral property assignsthe interest and retains a production payment. The payment is payable out of futureproduction from the property interest assigned. The other is a carved out productionpayment. It is created when an owner of any interest in a mineral property assigns aproduction payment to another person but retains the interest in the property fromwhich the production payment is assigned. Generally, a production payment is treated as a mortgage loan on the property anddoes not qualify as an economic interest in the mineral property. There is an exceptionwhere the consideration given for the production payment is pledged for developmentof the property, or if the production payment is retained upon the lease of the mineralproperty. In such situations, the payment will qualify as an economic interest and the payments made to the holder pursuant to the production payment agreement is treatedas ordinary income (IRC section 636(c)). In some cases, the transaction should betreated as a sale of an overriding royalty interest. As an example, even when theproduction payment is pledged for exploration and development of the property, if thelease is undeveloped and mineral reserves have not been established and proven insufficient quantities to generate enough income to retire the production payment(including interest) prior to the time that the lease is abandoned, the payment is notclassified as either a loan or as a production payment pledged for development. Treas. Reg. section 1.636-3 requires that the life of the production payment must be shorterthan the life of the property. Therefore, for an unexplored (wildcat) property, if nominerals are discovered or the reserves are in such small quantities that they will neverpay off the production payment, the production payment's life will exist until the leaseis abandoned. Once the lease is abandoned the transaction must be classified by thepayor as a purchase of an overriding royalty interest, capitalized by the payor andtreated as capital gain income by the payee. The burden of proof is on the taxpayer that the production payment will be retiredprior to the time the lease is abandoned. Before a producing well has been drilled onthe lease, proof is almost impossible.

Damages

When a taxpayer drills a well, the surface area of the land can be damaged. The ownerof the surface rights is entitled to reimbursement for damages. The contract and/orsupporting documents should be inspected to determine what type of damage paymentis being made. The amount representing compensatory damages due to loss of profitis taxable as ordinary income. For example, payments made specifically for cropdamage are taxable as ordinary income to the recipient. The amount representingdamages for destruction of business and goodwill is nontaxable to the extent it doesnot exceed cost or other unrecoverable basis, and it is taxable as IRC section 1231gain where there is no recoverable basis or the recoverable basis is exceeded. (Rev. Rul. 53-271, 1953-2 C.B. 36; modified by Rev. Rul. 83-49, 1983-1 C.B. 191) Amounts paid for expected damages, but where no damage was done, do not qualifyfor treatment as return of capital. It was held in Gilbertz v. United States, 808 F.2d1374 (10th Cir. 1987), rev'g 574 F. Supp. 177 (D Wyo. 1984), that payments foranticipated damages are ordinary income and not return of capital.

Shooting Rights

An operator may not want to incur the costs of entering into a lease on a property. Inmost cases, the taxpayer is attempting to avoid the high costs of lease bonuses. Accordingly, the operator will enter into a contract with the landowner to pay asmaller amount under a contract which gives the operator the right to enter onto theproperty and conduct exploration activities, but grants no drilling or production rights.

These limited rights are referred to as shooting rights. The amounts received by thelandowner in exchange for the shooting rights are ordinary income. Examiners shouldinspect the shooting rights contract and compare the sum stated to what wasreported.

Figure 3-1 is a chart illustrating the tax treatment of payments under an oil and gaslease.

Tax Treatment of Payments Under an Oil and Gas Lease

TypePayor or LesseePayee or LessorBONUSCapitalizeOrdinary IncomeBasic consideration for executinglease. Treas. Reg. section 1.612-3(a)(3)Percentage deletion allowed to August17, 1986. Only cost depl. after August17, 1986. Treas. Reg. 1.612-3(a)(1) INSTALLMENT BONUSCapitalizeOrdinary IncomeAlso consideration for granting alease; advance payment for oil; each installment is usually largerthan normal delay rental.

Rev. Rul. 68-606, total amountincludible at time of signing lease ifright to income is transferable. Gener- ally, this treatment is the same as forlease bonus.

DELAY RENTALPure rent; a payment to deferdevelopment rather than apayment for oil. Before capitalize Delay Rentalconsult PIP for the currentposition under IRC section 263A. Ordinary IncomeNo depletion.

ROYALTYDeductibleOrdinary IncomePayment for oil or gas.See Rev. Rul. 72-165 when advalorem taxes are involved. Subject to depletion (percentage orcost); percentage depletion is allowed ifpayee qualifies under IRC section613A. ADVANCE ROYALTYDeductibleOrdinary IncomeRoyalty payment made beforeproduction of minerals. See Rev. Rul. 72-165 when advalorem taxes are involved.

Subject to cost depletion in yearpayments are made. Percentagedepletion allowed until August 17,1986. ADVANCED MINIMUMROYALTYMinimum royalty paymentrequired by contract terms.

DeductibleAt option of payor: (1) In yearpaid or accrued or (2) When oil orgas is sold or recovered. Treas. Reg. section 1.612-3(b)(3)

Subject tpercenta1986.

Ordinary Incomeo cost depletion. Allowedge depletion until August 17,

Tax Treatment of Payments Under an Oil and Gas Lease (continued)

TypePayor or LesseePayee or LessorPRODUCTION PAYMENTS_______________

RETAINED

(SALES TRANSACTION)

Not an economic interest. Is treated as amortgage.

_______________

RETAINED

(LEASING TRANSACTION)

An economic interest.

_______________

CARVED OUT AND SOLD:

NOT AN ECONOMIC INTERESTSimply a loan.

_______________

CARVED OUT AND SOLD:

AN ECONOMIC INTERESTthat is, pledged for development of property.

Repayment of principal and interest expense.

_______________

Capitalize, bonus paid in installments.

Treas. Reg. section 1.636-2(a).

_______________

Repayment of principal and interest expense.

_______________

Capitalize as installment lease bonus.

Repayment of principal and interest income.

_______________

Ordinary income. Subject to depletion(percentage or cost). Treas. Reg. section1.636-2(b).

_______________

Repayment of principal and interest income.

_______________

Ordinary, depletable income.

DAMAGES_______________

BUSINESS ANDGOODWILL

that is, surface damages.

_______________

LOSS OF PROFIT

that is, crop damages.

_______________

ANTICIPATED DAMAGESBUT NONE WAS DONEAmount paid based on the anticipation thatdamages would occur.

If acquired or leased, capitalize as G & Gcosts.

If not acquired or leased, expense.

_______________

If acquired or leased, capitalize as G & Gcosts.

If not acquired or leased, expense.

_______________

If acquired or leased, capitalize as G & Gcosts.

If not acquired or leased, expense.

Return of capital to the extent of basis of theproperty.

Amounts in excess of basis are IRC section1231 gain.

_______________

Ordinary Income.

_______________

Ordinary Income.

Tax Treatment of Payments Under an Oil and Gas Lease (continued)

TypePayor or LesseePayee or LessorSHOOTING RIGHTS_______________

PURE CONTRACTCapitalized as G & G.Ordinary income.

_____________________________________________

CONTRACT WITH OPTION TOIf acquired or leased, treat as lease bonus.Ordinary income. Cost depletion allowedACQUIRE OR LEASE_______________only after August 17, 1986.

If not acquired or leased, expense in year_______________

option expires.Ordinary income.

UNIFORM CAPITALIZATION RULES -- IRC SECTION 263A

IRC section 263A is the written expression of the U.S. Congress' intent to apply auniform set of capitalization rules to all costs incurred in manufacturing orconstructing property or in purchasing and holding property for resale. Costs relatingto the production of real or tangible personal property and the purchasing and holdingof property for resale are subject to uniform capitalization (UNICAP) rules.

Produced Property

The industry has recognized the self-constructed asset as tangible or surface wellequipment. The asset construction rules in IRC section 263A generally apply toconstruction of assets used, or to be used, in a trade or business. The rules also applyto assets described in IRC section 1231. However, controversy surrounds theleasehold mineral interests. The term produce, as described in IRC section 263A(g), includes construct, build, install, manufacture, develop, or improve. Historically, IRCsection 341(b) also contains this same language: manufacture, construction, orproduction of property.

Rev. Rul. 57-346, 1957-2 C.B. 236, holds, under IRC section 341(b)(1), that acorporation engaged in acquisition and development of oil properties is considered tobe involved in the construction or development activities that increased the value ofthe properties. Rev. Rul. 68-226, 1968-1 C.B. 362, defines an oil and gas leasehold asan interest in real property. These rulings support the Service's position thathistorically a mineral interest is real property. Thus, a taxpayer who acquires anddevelops oil or gas properties is engaged in a developmental activity within themeaning of IRC section 263A. Produced property could include G & G data, acquiring and developing the leasehold mineral interest, constructing tangible and surface well equipment, and carrying oil and gas inventory (barrels of oil and MCF ofgas). It does not include acquiring undeveloped leases.

Predevelopment Expenses

The discussion that follows will detail some areas where IRC section 263A may affectoil and gas operations. Many oil operators maintain inventories of undrilled leases forresale to others or transfer to limited partnerships. The rules relating to inventoriesshould be applied in this area. Exploration, drilling, and development activities couldbe construed as activities which improve property. The Tax Court has held in variousdecisions, including Sun Company, Inc. v. Commissioner, 74 T.C. 1481 (1980), aff'd, 677 F.2d 294 (3rd Cir. 1982), that exploration and developmental drilling could not bedistinguished for IDC purposes. However, it has been held that exploration isconsidered a separate activity from development and production. (Shell Oil Co. v. Commissioner, 89 T.C. 371 (1987), rev'd, 952 F.2d 885 (5th Cir. 1992)). IDC is specifically exempt from the boundaries of IRC section 263A, but therules may apply to production of oil if an inventory of oil is on hand at the end of theyear. Examiners should take caution in this area as most taxpayers have little or noinventory on hand at the end of the tax year. Geological and geophysical activitiesshould be allocated an appropriate share of indirect costs. Treas. Reg. section1.263A-1(b) lists costs which are excepted from the UNICAP rules. IRC section 263A requires costs that have been traditionally capitalized to continue tobe capitalized. Also, there are other costs that are known as additional IRC section263A costs. These include direct costs, indirect costs, mixed service costs, and certaininterest costs. Each of these costs are discussed below.

1.Direct costs are labor and material that are directly related to a property. Directmaterials are those that are a part of the property or consumed in the activity. Direct labor costs are labor costs including fringe benefits which are associatedwith the property or activity. These costs have traditionally been capitalized.

2.Indirect costs are all other costs that directly benefit production, or are incurredbecause of the production activity. If they benefit more than one activity, theyneed to be allocated on a reasonable basis to the activities involved. Treas. Reg. section 1.263A-1(e)(3)(ii) has an extensive list of indirect costs that must becapitalized. If there is a question as to whether an indirect cost should beallocated, refer to Treas. Reg. section 1.263A-1(e)(3)(iii). This section of theregulations discusses additional indirect costs that are not required to be allocated.

3.Mixed service costs are costs of administrative, service, or support departments oractivities which benefit more than one activity. These costs must be allocated, ona reasonable basis, to the activities which benefitted from them.

4.Interest costs incurred to finance the production of property must be capitalized, if the property produced is:

a.Real property, orb.Personal property with a MACRS life of 20 years or more, orc.Personal property with an estimated production .now, period of more than 2years, ord.Personal property with an estimated production period of more than oneyear and the estimated cost of production exceeds $1 million.

INTEREST CAPITALIZATION

Under the interest capitalization rules, the interest to be capitalized is the interest thatwould have been avoided if the production expenditures relating to the property oractivity had not been made, and the funds were used to repay the debts of thetaxpayer. Debt which can be traced specifically to an activity is allocated to thatactivity. If the production expenditures relating to an activity exceed the debt tracedto the activity, other debt must be allocated to the activity. Interest on debt allocable to leasehold costs should be capitalized during theproduction period because mineral leases are real property. It has not been determinedwhether the entire leasehold cost is included in the base if only a portion of theproperty is under construction. For further guidance in this aspect of the UNICAPrules, refer to the final regulations under IRC section 263A(f) published in December1994. In the case of onshore activities, the production period for a unit begins on the firstdate physical site preparation activities are undertaken with respect to that unit (forexample, building an access road, leveling a site for a drilling rig, or excavating a mudpit). In the case of offshore activities, the production period for a unit begins on thefirst date physical site preparation activities (for example, drilling to drive the piles) other than activities undertaken with respect to expendable wells, are undertaken. Anexpendable well is a well drilled solely to determine the location and delineation ofhydrocarbon deposits. The production period ends when the well is ready to produce.

ALLOCATION OF INDIRECT COSTS

The Code and Treasury Regulations do not specify how the indirect costs are to beallocated. But the regulations provide several simplified methods that are availableto the taxpayer. The indirect costs should be matched with the activities that benefitfrom the incurred costs. The taxpayer should use the same method for allocating overhead. The allocation method should be used consistently and for all federal taxpurposes. Taxpayers in the petroleum industry use different accounting methods to allocateindirect costs. The accounting methods fall under two categories: facts andcircumstances methods and simplified methods. Under the facts and circumstancesconcept, taxpayers use the specific identification method, burden rate, or standard costmethod, and any other reasonable method of allocation. The simplified service costmethod and simplified production method is used in allocating indirect costs under thesimplified concept. The final regulations added an exception for certain producers, who use the simplifiedproduction method, with total indirect costs of $200,000 or less. Treas. Reg. section1.263A-1(b)(12) and section 1.263A-2(b)(3)(iv) set out the exception. The smallmanufacturer exception applies when a producer uses the simplified productionmethod and incurs $200,000 or less of total indirect costs in a taxable year; theadditional IRC section 263A costs allocable to eligible property remaining on hand atthe close of the taxable year are deemed to be zero.

CONCLUSION

In conclusion, specific items to which IRC section 263A may apply are G & Gactivities, leasehold costs, tangible well equipment, surface production equipment, andinventory. Intangible drilling costs are excluded from section 263A, but overhead maystill be allocated.

AUDITING TECHNIQUES

Notice 88-99, Treas. Reg. section 1.263A-0 through 1.263A-3, and Treas. Reg. section 1.263A(f)-O through 1.263A(f)-9 are the most useful tools for conducting anexamination with regard to items relating to IRC section 263A. In addition to the notice and regulation sections set out above, some suggested audittechniques are set out below that are useful in conducting an examination involving theUNICAP rules.

1.Did the taxpayer take IRC section 263A into account when they prepared theirtax return? If it was not taken into account, devise an allocation method based onthe rules listed in the regulations.

2.Determine if the taxpayer correctly handled the production period. If not, youmust determine the correct production period.

3.Determine if the taxpayer meets the definition of a qualified small manufacturer.

One is a small manufacturer if it uses the simplified production method and, during its tax year, incurs total indirect costs of $200,000 or less. If the totalindirect costs meet this criteria, the additional IRC section 263A costs may betreated as zero.

4.If the taxpayer is a reseller, determine if the average gross receipts during the last3-year period is $10 million or more. If this de minimis rule is satisfied, thetaxpayer will be exempt from IRC section 263A.

5.If the taxpayer has an inventory of oil on hand at the end of the year, ensure thatall items are correctly capitalized.

6.If no exceptions apply and the taxpayer maintains an inventory of undrilled leasesfor resale to others or for transfer to limited partnerships, make sure that IRCsection 263A was correctly applied.

7.Determine if the taxpayer was drilling any wells in the year of audit. Inspectother sources such as annual reports, general ledger additions, or minutes todetermine other self construction projects.

8.If the taxpayer has interest expense related to their production of oil and gas, verify that the correct amount of interest was capitalized.

a.Determine whether the taxpayer has used the proper interest capitalizationperiod on leasehold development.

b.Determine the proper application of the now repealed IRC section 189. Uniform capitalization rules apply to interest paid or incurred afterDecember 31, 1986, on debt incurred before December 31, 1986, to theextent IRC section 189 applied before its repeal. A leasehold was realproperty covered under section 189 for interest capitalization purposes.

c.Obtain FASB 34 calculations for interest capitalization to ascertain theaverage effective interest capitalization period. Identify constructionprojects subject to interest capitalization.

LEASEHOLD COST

The costs associated with acquiring or retaining a lease are classified as leaseholdcosts. These costs are considered capital expenditures. Many taxpayers willmisclassify the costs associated with obtaining a lease to various expense accounts andonly capitalize the lease bonus. Test lease operating cost, legal and accounting, officesupplies, travel and entertainment, miscellaneous, and similar accounts for acquisitioncosts that may have been deducted as current expenses. Examining officers shouldrefer to INDOPCO, Inc. v. Commissioner, 112 S. Ct. 1039 (1992), with regard tolegal expenses. It was held in this case that legal expenses were nondeductible capitalexpenditures.

In some cases, an advance royalty is, in fact, a disguised lease bonus. The Serviceutilizes Anderson v. Helvering, 310 U.S. 404 (1940), 24 A.F.T.R. 867, 40-1 U.S.T.C. 553, for treating a payment as a lease bonus subject to capitalization as leaseacquisition costs. This classification is made if the lease instrument provides for anadvance royalty to be paid to the mineral and royalty owner, regardless of whetherproduction of the mineral ever occurs, and there is no refund provision. Leasehold costs include commissions or finders fees, abstracting costs, attorney's feesfor title opinions, drafting deeds, and instruments of conveyance. If the propertypurchased already has production, there may be engineering costs involved in theappraisal of the equipment and a study of the oil and gas reserves. Some companieshave sufficient leasing activity to warrant the services of a landman, a personexperienced in mineral leasing activities. The landman's salary/contract labor shouldbe a part of the capitalized leasehold cost, if they can be attributed to the acquisition ofa particular mineral lease. The same would be true with respect to a leasingdepartment. Not all of the efforts of a landman or a leasing department will result inthe acquisition of a lease. In such instances, costs should be allocated between thesuccessful and unsuccessful attempts of acquiring leases on some reasonable basis, ifan adjustment would be material. Scan the nonproducing lease account in the asset section of the ledger to determine thenumber and names of leases acquired during the year. This is done to become familiarwith the nonproducing leases and assist in determining whether capital costs associatedwith those properties have been incorrectly expensed. If a lease expires, a taxpayer is allowed to write off the capitalized cost of the lease, even if a new lease is later obtained on the same property. A loss is not allowed if anew lease is obtained covering the property (known as a top lease) prior to theexpiration of a lease. The cost of the old and new lease are capitalized to the sameproperty. Taxpayers sometimes denote a renewal of a lease by adding R immediately after the identification number of the property. Once renewal leases areidentified, examiners should check to ensure that the costs of renewal are capitalizedto the leaseholds and the original leasehold costs have not been written off.

Below are some examples of leasehold costs that should be capitalized.

1.Research of lease location by engineer, geologist, etc. for purposes other thanlocating a well.

2.G & G expenditures leading to acquisition or retention of an oil and gas property.

3.Expenses in connection with leasing the property from a landowner.

4.Legal costs of securing a lease and clearing the 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.

9.Seismic work to determine the size of the reservoir or reserve.

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 inconnection with prior IDC.

14.Bottom-hole contribution when paid to obtain information which enhances thevalue of the property.

15.IDC, if there is no election to expense.

16.Delay rentals, when election is made to capitalize.

GEOLOGICAL AND GEOPHYSICAL (G & G) COSTS

An operator planning to lease property does not do so without acquiring someinformation about the prospect. Initial information is obtained through the use of G & G exploration methods. Geological methods consist of the search of a surface forindications of hydrocarbons, geological mapping, topographical mapping, aerialphotography, and radiation surveying, to name a few. When enough information isobtained to show favorable conditions for oil or gas, the lease is acquired andadditional exploration is performed to further define the prospect. The exploration costs that lead to the acquisition or retention of mineral propertiesmust be capitalized as part of the cost of the properties. You will usually encounterthis issue when auditing an operator. The operator may use either in-house or outsideengineers and geologists to lease and develop unproven properties or to decide topurchase productive properties. Most operators will capitalize the costs that werepaid to engineers and geologists outside the company, but they will not capitalize aportion of the salaries and overhead allocable to in-house personnel who perform thesame types of services. The amount of G & G costs to be capitalized by a taxpayer depends upon thetaxpayer's operations. In some cases, taxpayers will limit their business activities topurchasing properties which are already producing. The seller already has incurred the G & G costs necessary to drill a successful well which is reflected in a higher purchaseprice. The purchase price is capitalized to leasehold costs along with additional G & G or other investigating costs which are incurred in evaluating the property to bepurchased. At the opposite end of the business spectrum, large corporate taxpayers may identifyand develop their own prospects completely through the use of their own in-housespecialists. The taxpayer will usually identify a project area and conduct areconnaissance type survey. Based on this survey, smaller areas of interest(noncontiguous project portions which warrant detailed G & G costs) will be identifiedwithin the project area. The costs associated with these surveys must be allocatedequally among the areas of interest, even if the acreage contained in the areas ofinterest are different. For example, a taxpayer spends $9,000 and identifies three areasof interest in a project area. One-third of the $9,000 or $3,000 must be capitalized toeach area of interest even if one area of interest is substantially bigger than the othertwo. The costs assigned to an area of interest can only be written off when the area ofinterest is abandoned. Often, a taxpayer will claim that there are more areas of interest than really exist. Thisclaim is made so the taxpayer can assign a portion of the survey costs to the area andthen quickly write the costs off through abandonment. If this appears to be the case, the help of an Engineer may be needed in identifying an area of interest.

By definition, an area of interest is an identified area where more intense G & Gexploration methods will be employed. If no additional costs are incurred on analleged area of interest after the initial surveys, then the area was never an area ofinterest. The related costs should be reallocated to other legitimate areas of interest. After initial G & G work, decisions are made to acquire leases, investigate further, orabandon the costs incurred to date. Sometimes several years will pass before thetaxpayer will make the decision to acquire a lease. Examiners need to determine theproper taxable period in which the final or controlling decision was made. Also, ifacreage is acquired with the lease, the costs accumulated are allocated based on thenet acreage acquired. Using the example set out above, where $3,000 of G & G costs was capitalized to aproject area, suppose that the taxpayer leases a 25 percent working interest in 40 acresand a 50 percent working interest in 10 acres all in the first project area. The $3,000of G & G costs will now have to be allocated among the leased acreage based on thefollowing formula:

Equivalent WorkingGross AcresInterestNet AcresAllocation FractionAllocationLease #14025%1010/15$2,000Lease #21050% 55/15$1,000

Totals15

For the purpose of converting a royalty interest to an equivalent working interest, inthe example set out above, the royalty ownership percentage should be doubled. When dealing with an oil and gas operation which conducts a significant amount of itsown exploration in-house, the taxpayer should also be required to capitalize a portionof its corporate overhead to its exploration activities using reasonable cost accountingmethods, in addition to the direct costs. If assistance is required, the services of an Engineer should be requested. Even if anengineer assists with the examination, certain information can be obtained early in theaudit. Set out below are suggested audit techniques examiners can utilize whenconducting an investigation of G & G costs.

1.Determine whether the taxpayer develops its own properties or acquires alreadyproducing properties.

2.If the property is already productive, someone has spent time analyzing data aboutits potential productivity. The cost of that person's time should be determined andcapitalized to the leasehold cost along with any related overhead. This should be done for any properties that were purchased during the year or stillbeing investigated for purchase at year-end.

a.Request the taxpayer to provide you with a list of the properties acquiredduring the current year and/or properties they were trying to acquire at year- end.

b.Determine the persons involved in providing and analyzing the information andmaking the purchasing decisions of the lease (that is, geologist and engineerswho interpret or produce data, etc.).

c.Determine these persons' salaries and the associated overhead allocable to theirsalaries, if in-house personnel were used. For detail on this, see OverheadAllocation later in this chapter.

d.Verify the cost incurred to shoot the G & G. Ensure that direct and indirectcosts are properly included in the G & G amount for each respective project.

e.Capitalize these costs to leasehold cost.

3.If the property is an unproductive property, the taxpayer may have started with aproject area, an area of interest, or a lease. Determine at what point the taxpayerbegan incurring costs. Identify the costs involved and whether they were handledproperly.

a.Have the taxpayer identify the project area, areas of interest, and leasesacquired or to be acquired, by name and on a map or plat. An engineer may be needed because some taxpayers have a problem identifying too many areas ofinterest in a project area.

b.Identify the reconnaissance survey cost on a project area and determine if itwas allocated equally among the areas of interest that have been delineated. Ifnone are acquired, the costs can be deducted under IRC section 165.

c.Identify the detailed survey cost performed on the areas of interest. Determineif they were allocated based on a net acreage basis to the lease(s) obtained. Ifleases were acquired adjacent to the area of interest due to the reconnaissancesurvey and detailed survey, the allocated costs of the reconnaissance surveyand the cost of the detail survey are capitalized to the lease(s) acquired. If nolease is acquired in the entire area of interest, then the cost is deductible underIRC section 165.

d.Identify the geologists and engineers who worked on each project area, area ofinterest, and/or lease. Determine what portion of their salaries should becapitalized to the leases acquired. Interview the taxpayer and thegeologists/engineers. Have them assist you in arriving at the amounts tocapitalize. If they are uncooperative, you may need the help of an IRSEngineer.

e.Identify the amount and the items in overhead that should be allocated basedon a reasonable method for allocation. For detail on this, see OverheadAllocation later in this chapter.

f.The amounts capitalized are added to the basis of the leasehold costs ofacquired leases. If the property was productive in the year of the examination, an additional cost depletion deduction may be required if cost depletion wouldbe greater than percentage depletion.

4.Remember that not all project areas or properties that the taxpayer looked at willbe pursued. Determine if the taxpayer will be allowed to write off the costsincurred for the geologist salaries, the reconnaissance survey and detailed surveysas an abandonment. Rev. Rul. 77-188, 1977-1 C.B. 76 and Rev. Rul. 83-105, 1983-2 C.B. 51, offer moreinsight to the tax treatment of G & G costs. Louisiana Land and Exploration Co. v. Commissioner, 7 T.C. 507 (1946), aff'd on other issues, 161 F.2d 842 (5th Cir. 1947), gives further guidance in this area.

ABANDONMENT COST

When a property is determined to be unproductive, the lessee will want to write off thecosts associated with the unproductive property. The amount of the deduction for abandonment costs depends upon the stage of development of the property. Thetiming of the deduction for abandonment is based on certain identifiable events. For the lessee, losses from unproductive properties may be deducted in the followingsituations:

1.Abandonment of Unproved Property: A lessee will incur G & G costs, along withother costs of developing a project area and areas of interest, long before anyleases are entered into. Many times a lease is not acquired or the project is putaside for a while to wait for the right time for further development. Often, ataxpayer will use this hiatus in activity to claim an abandonment loss, even thoughthe taxpayer has no present intent to abandon the property. If no reserves arefound in a project area or an area of interest, the costs associated with the area areallowed to be written off as an abandonment loss. Once reserves are determinedto exist, Rev. Rul. 77-188 and Rev. Rul. 83-105 require that an identifiable event occur before a write off will be allowed. These rulings hold that an identifiableevent would occur when one of the following exists:

a.There is a lease sale that includes the area of interest involved and the entity isunsuccessful in obtaining a lease.

b.There is an indication that the area of interest will not be included in a leasesale.

c.There is an event that establishes that the area of interest is worthless.

Rev. Rul. 83-105 suggests that where exploration is conducted offshore, or onGovernment interests onshore, the passage of 10 years without the areas havingbeen included in a lease sale, or without an indication that the area will be soincluded, is considered to be an event warranting a deduction of related costs. Foronshore interests, other than Government interests, the passage of 5 years isconsidered to be an identifiable event if no earlier identifiable event occurs. 2.Abandonment of Lease: An abandonment loss may be deducted in the year inwhich the property is deemed worthless. A property is deemed worthless if thetitle is abandoned through relinquishment. Title relinquishment is considered to bea closed and completed transaction, thereby proving worthlessness. Without therelinquishment of title, leasehold costs should not be written off. A copy of thelease should be secured to determine if it has been relinquished. The lease willhave a primary-term clause and a delay-rental clause. (Exhibit 1-1 is an example ofa mineral lease.) Delay rentals are paid to defer the drilling activity for designatedperiods of time within the primary term. Drilling cannot be deferred beyond theprimary term by payment of delay rentals. The timely payment of delay rentals andtimely drilling keeps the lease in effect. However, if delay rentals are not paidtimely or drilling has not commenced within the primary term, then the taxpayermust forfeit the lease.

Another way a taxpayer may relinquish title to a lease is to execute a quit claimdeed. A quit claim deed transfers the title to the mineral interest back to the lessor. Once the taxpayer relinquishes title to the lease, the taxpayer will be allowed anabandonment loss. The amount of the loss will be the adjusted basis of theleasehold costs and the costs associated with any unamortized IDC, if the taxpayerpreviously elected to capitalize IDC.

3.Abandonment of Lease and Well Equipment: When a reserve is depleted, theadjusted basis of lease and well equipment may be written off when the well(s) areabandoned, even when the lease is not abandoned. A plug and abandonmentreport may be filed with the appropriate state agency when a well is abandoned. (Exhibit 3-2 is an example of Form W-3, which is required by the State of Texas.) This report should be inspected to determine when the abandonment actuallyoccurred. The examiner should determine what happened to the equipment afterits removal from the lease, since it could have been transferred to another lease ora warehouse facility awaiting assignment to another lease. Any salvage valuereceived for the lease and well equipment should reduce any loss claimed on theequipment.

4.Abandonment of Dry Hole Costs: When a well is determined to be a dry hole, thetaxpayer is allowed to write off the IDC incurred as dry hole costs. A separateelection to expense dry hole costs is required if the taxpayer capitalizes IDC. Byexpensing IDC as dry hole costs, the taxpayer is not required to include these costsas an IDC tax preference item in computing alternative minimum tax. Thus, adetermination must be made that the well never produced oil or gas. If the amountof the dry hole costs written off is material, examiners should request the plug andabandonment report to substantiate that the well was abandoned. Leasehold costscannot be written off when a dry hole is drilled until title to the lease isrelinquished.

AUDIT TECHNIQUES

Abandonment losses can be very easy to verify. For example, if the well was pluggedand the report was filed with the proper state agency, the report would support anallowance of a deduction for the abandonment loss. However, examiners need toensure that the well was not reentered. In addition, it should be verified that theentire property under the definition of property was abandoned. Below are suggested audit techniques that examiners can utilize in the examination ofabandonment losses. The audit techniques are broken down into two categories: (1) Nonproductive properties where no leases have been executed. (2) Nonproductiveproperties where leases have been executed.

Nonproductive Properties (No Leases Executed):

1.Obtain a breakdown of the abandonment expense by amount and name.

2.Request a breakdown of the cost incurred on the properties.

3.Determine what the project area was, and what the areas of interest were.

a.Obtain a name and description from the taxpayer for the project area and theareas of interest.

b.Have the taxpayer show the boundaries of the project area and the areas ofinterest on a map or plat.

4.Determine if additional costs were expended on an area of interest after it wasidentified as such. If no additional costs were incurred, the area was probably nota true area of interest. If the amount is material, an engineer may be consulted.

5.If no reserves were determined in the whole project area, the costs associated withthe project may be abandoned.

a.Determine whether the amount expended applies only to the project area inquestion.

b.Test the allocation of the costs to the area of interest.

1)Costs that are not direct costs of an area of interest are allocated equallybetween areas of interest. Areas of disinterest in the project area shouldreceive no allocation.

2)Direct costs of an area of interest should be directly assigned to that area ofinterest.

6.If reserves were determined in a particular area of interest, but no lease wasacquired, determine that no lease was acquired by the following:

a.Question the taxpayer as to whether any leases were acquired in or adjacent tothe area of interest.

b.Scan subsequent year acquisitions to determine whether leases in this area ofinterest were acquired in a subsequent year.

7.Determine that an identifiable event has occurred allowing the write off of thecosts incurred. An identifiable event occurs when one of the following criteriaexists.

a.A lease sale that includes the area of interest involved and the taxpayer isunsuccessful in obtaining a lease;

b.An indication that the area of interest will not be included in a lease sale;

c.An event that establishes that the area of interest is worthless; ord.There has been an elapsed time of 5 years for onshore properties, or 10 yearsfor offshore or Government properties.

8.Verify the amount of the abandonment loss for the area of interest by testing theallocation of costs. Inspect records showing costs charged to the area of interest.

a.Costs that are not direct costs of an area of interest are allocated equallyamong the areas of interest. Areas of disinterest in the project area shouldreceive no allocation.

b.Direct costs of an area of interest should be directly assigned to that area ofinterest.

Nonproductive Properties (Executed Leases):

1.Obtain a list of the properties abandoned by the taxpayer.

2.Request the lease file on the abandoned properties.

a.Determine from the lease agreement if the primary term of the lease expiredduring the year under audit. (The primary term description of a lease wouldlook something like clause 2 per mineral lease sample, Part IV, Exhibit 1-1.)

1)If the lease has expired, the taxpayer has sustained a loss.

2)If the lease expired prior to the audit year, the loss would not be allowable inthe year of examination. However, if the prior year's statute of limitations hasnot expired, the loss would be allowable in the year of expiration.

b.If the primary term is still in effect, determine if the taxpayer ceased to paydelay rentals on the lease in the year under audit.

1)Inspect the lease agreement, and determine when payments should have beenmade. Determine if payment was not made. (The delay rental description of alease would look something like clause 5 per mineral sample, Part IV,

Exhibit 1-1.)

2)Inspect the delay rental record. The taxpayer will usually keep a delay rentalrecord for each nonproductive lease. This record usually has the amount, date, and to whom the delay rental was paid. If a payment was not made on the nextdue date, there may be a notation.

3)Inspect the lease file for any correspondence or notes about allowing the leaseto lapse.

a)If the delay rental date lapsed during the year under audit, the taxpayer hassustained a loss.

b)If the delay rental lapsed prior to the audit year, the loss would not beallowed.

c)If the delay rental was paid and in force during the audit year, a loss wouldnot be allowed unless a quit claim deed was executed or the primary leaseterm lapsed without production.

C.Determine if a quit-claim deed was executed by the taxpayer.

1)Inspect the lease file and ask for the quit claim deed. Ensure the date it wasexecuted is in the taxable year under examination.

2)If a quit claim deed was not executed in the audit year, the taxpayer will not beallowed an abandonment loss unless the primary term has lapsed withoutproduction or a delay rental was not paid in the audit year.

LEASE OPERATING EXPENSE

Operating expenses are deductible in accordance with the taxpayer's method ofaccounting. Therefore, it is important to be able to distinguish and categorize thevarious expenditures that will be encountered in an oil and gas producer's return. Examiners should be aware that there will be a tax impact for any material itemmisclassified as operating expense when in reality it is leasehold costs. In the oil andgas industry, operating expenses are commonly referred to as lease operating expense(LOE). It includes the cost of operating and maintaining producing leases. It alsoincludes the cost of labor for operating and maintaining the equipment on the lease, repairs and supplies, utilities, automobile and truck expenses, taxes, insurance, andoverhead expenses such as bookkeeping, billing costs, and correspondence. Operating expenses of oil and gas leases will include direct and indirect expenses anddepreciation. Operating costs on secondary and tertiary recovery projects aresomewhat higher because of the added expense of injecting water, gas, etc., into theproducing formation. The cost of the specialized equipment needed, such as pumps, tanks, boilers, high pressure wellhead equipment, etc., must be capitalized andrecovered through depreciation. The cost of operating the equipment is LOE.

Two judicial decisions, rendered in the 1930's, addressed the issue of LOE. Thefollowing is the gist of the opinions with regard to LOE: In the examination of lease operating expense, expenditures will be found forservicing the well, often called workover expenses, such as pulling rods, acidizing, fracturing, cleaning out, etc., all of which are operating expenses. Closelyassociated with these expenditures are others that have been held to be IDC, forexample, the fracturing of the producing sand with nitroglycerine before beingplaced in production and cleaning out of the well. The deepening of an existingwell is IDC. (P-M-K Petroleum Co. v. Commissioner, 24 B.T.A. 360 (1931), rev'd, 66 F.2d 1009(8th Cir. 1933), 12 A.F.T.R. 1335 and Monrove Oil Co. v. Commissioner, 28 B.T.A. 335 (1933), aff'd on another issue, 83 F.2d 417 (9th Cir. 1936), 17 A.F.T.R. 978, 36-1U.S.T.C. 521.) There is no simple way of distinguishing workover costs that are proper operatingcosts from those that are IDC. Inspection of invoices or AFEs will reveal deepeningexpenses. This will be obvious from an inspection of the invoices. Fracturing of theproducing zone in a well before it has produced oil is a fact that will have to bedetermined from the production records or other sources of information that should bein the possession of the taxpayer. Before spending a lot of time on this item, consider the tax impact. If the taxpayer haselected to expense IDC and there is no prospect for alternative minimum tax, there isno point in examining this area or attempting to distinguish IDC from operating costs.

The following are examples of lease operating expenses:

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 on the lease.

11.Lease signs.

12.Salaries of other operating personnel: farm boss, engineer, etc.

13.Salt water disposal costs.

14.Rental payments to mineral owner when not based on production.

15.Allocable portion of overhead costs.

16.Qualified tertiary injection expenses.

Even though it was noted earlier that LOE was not a very productive issue, it isimportant to distinguish between LOE and IDC. Lease operating expenses make upthe bulk of cost of goods sold on oil and gas properties. Although both, LOE andIDC, are fully deductible in the current period, only IDC is a tax preference item foralternative minimum tax.

BAD DEBTS (JOINT INTEREST OWNERS)

This issue will be found when auditing an operator that has claimed bad debts inconnection with joint interest billings. When taxpayers first become the operator of aproperty, they enter into an operating agreement with all the working interest owners. This is a standard agreement and gives both the working interest owner and theoperator certain rights and recourse if the agreement is violated. One of the duties ofthe operator is to collect the joint interest payments from the working interest ownerswho have joined together to develop and operate the property under the operatingagreement. Sometimes a working interest owner will refuse to pay its share of the drilling oroperating costs of a well or property. When this happens, the operator has certainsteps to take to recoup its funds under the operating agreement. If the property is aproducing property and the operator is receiving the disbursements from the purchaserto distribute to the working interest owners, the operator can offset the nonpayingworking interest owner's share of distributions against the funds owed to the operatoron that particular property. If a property is dry, minimally productive (that is, theincome from the property does not cover the operating cost), or the purchaser paysthe nonpaying working interest owner directly, the operator may sue the nonworkinginterest owner for breach of contract for nonpayment of its joint interest billings. Thecourt may assign the interest of the nonpaying working interest owner to the operatorif the property is productive, or it may file a judgment against the nonpaying workinginterest owner. Judgments are very hard to collect. If the property is productive, thecourt also may direct the purchaser to suspend all payments to the nonpaying workinginterest owner until the case is settled.

Suspended funds received by the operator from the purchaser pursuant to a courtsettlement reduces the bad debt deduction claimed. If the funds exceed the bad debtdeduction claimed, the excess must be included as ordinary income. If the operator is assigned the interest in the nonpaying working interest owner'sproperty, the bad debt deduction must be reduced by the amount of the fair marketvalue of the property received and assign this value to the leasehold cost of the newinterest in the property. A determination of the fair market value of the property at thetime of the court settlement or final decree must be made, if these documents do notprovide a value. Usually the taxpayer will already have an interest in the sameproperty. Reserves would have been determined for the operator's interest in theproperty for the year for financial or tax depletion purposes. The reserve report willusually have a discounted cash value of the property that can be used for fair marketvalue purposes. Thus, you will have to convert the operator's value to 100 percent ofthe property value and multiply it by the nonpaying working interest owner's interest. Examiners should be cautioned that when the working interest revenue and expensepercentage are not the same, additional steps must be taken. The steps describedabove are very general. However, if one is investigating a fair market valuation issuethat is material in amount the assistance of an engineer is needed. Sometimes the operator will no longer want to deal with the nonpaying workinginterest owner because of all the continuing problems it has had collecting its cost. When this happens, the operator might purchase the nonpaying working interestowner's interest in the property as part of the settlement. If this happens, the purchaseprice will usually be spelled out in the settlement documents. Examiners should secure a list of the items and amounts that make up the bad debtdeduction from the taxpayer. When making the request for the list, also ask thetaxpayer to provide an explanation of each item and how each amount of the bad debtwas calculated. The calculation should be reviewed. There might be materialadditions and reductions to the net bad debt deduction. Determine the nature of theseadditions and/or reductions by looking at the underlying source document. If any of the items were due to nonpayment of joint interest billings, ask the taxpayerwhat steps were taken to obtain payment. If no steps were taken, ask why. Mostoperating agreements will give the operator specific remedies for nonpayment. If theproperty was nonproductive, determine whether the taxpayer is dealing with the sameperson on other new ventures. Determine the circumstances for the nonpayment andthe reason for allowing this person in any new ventures. The following are two basicquestions that examining officers should ask the taxpayer: 1.Has the taxpayer requested payment from the joint interest owner or was anylitigation attempted? 2.What was the outcome of the litigation?

Examiners should, also, request the correspondence file for each bad debt in questionand settlement contracts. These contracts should provide the terms of any settlementsreached. Compare the information obtained from the correspondence file and thesettlement file to the amount of the bad debt and how it was calculated. If suspendedproceeds were received, determine whether the taxpayer reduced its accountsreceivable from the joint interest owner by the funds received before arriving at theamount claimed as the bad debt. If property was received as part of the settlement, the fair market value should reducethe amount owed to the taxpayer before arriving at the bad debt deduction. Examinersshould determine that the correct fair market value of the property was used to reducethe total amount owed to the operator before arriving at the bad debt deduction. To determine whether the fair market value claimed is correct, the following stepsshould be taken:

1.Obtain copies of the operator's reserve calculations for the property in question. Usually the taxpayer will already have another interest in the property in question.

2.Determine the fair market value of the property received by using the discountedcash flow value of the property.

3.If the working interest revenue and expense ownership interest are different, additional steps may be required. If the fair market value is material, consult anIRS Engineer.

4.Compare the value arrived at to the fair market value which the taxpayer used.

INTANGIBLE DRILLING COST (IDC)

There are many costs incurred in developing an oil and gas well. For tax purposes, these costs are classified into two groups: IDC and tangible equipment costs. Thedistinction between these two costs is very important; they are treated differently fortax purposes. Before we discuss the tax treatment, we must first be able to identifythose costs which are intangible drilling and development costs, also known as IDC. IDC are expenditures for drilling wells or developing wells (preparing them toproduce) which are intangible, or which have no salvage value in themselves. Pursuant to Treas. Reg. section 1.612-4(a), IDC are *** expenditures made by anoperator for wages, fuel, repairs, hauling, supplies, etc., incident to and necessary forthe drilling of wells and the preparation of the well for the production of oil and gas. Rev. Rul. 70-414, 1970-2 C.B. 132, sets out costs which are typically IDC, notoptional costs, but were held to be tangible equipment.

Therefore, IDC are all costs which are the intangible or nonsalvageable costs ofdrilling up to and including the cost of installing the Christmas tree. The termChristmas tree refers to the pipes, valves, and fittings that are used to regulate theflow of oil and gas from the wellhead. Many times, the physical arrangement of thesepipes and valves resemble a Christmas tree. The cost of casing and the physicalcomponents of the Christmas tree are not IDC, but equipment costs which arecapitalized and depreciated. The following are examples of IDC:

1.Administrative costs in connection with drilling contracts.

2.Survey and seismic costs to locate a well site on leased property.

3.Cost 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.

Now that we have identified IDC, we can discuss the tax treatment of these costs. Aworking interest owner in an oil or gas property has the option to elect to currentlydeduct IDC. This option, granted by Treas. Reg. section 1.612-4(a), is exercised byclaiming IDC as a deduction on the taxpayer's return for the first taxable year in whichthe taxpayer pays or incurs such costs. No formal statement is necessary. If theowner of the lease is a partnership, the election must be made at the partnership level. Once the election is made, it is irrevocable and binding for all subsequent taxableyears. A taxpayer who fails to claim the expenses on the first return as a deduction isdeemed to have elected to capitalize the costs. The filing of an amended return afterthe due date of a timely filed return will not change the initial election. If a taxpayer fails to deduct IDC as an expense on the first return, the taxpayer isdeemed to have elected to capitalize such costs. Recovery of costs will be donethrough depletion, to the extent that they are not represented by physical property, andthrough depreciation, to the extent that they are represented by physical property. Taxpayers that have made the irrevocable election to expense IDC under IRC section263(c) have the opportunity to make a secondary election to capitalize all or any partof the IDC incurred during a taxable year. This secondary election is not extended totaxpayers who have made the irrevocable election to capitalize IDC. Intangibledrilling costs paid or incurred in tax years beginning after December 31, 1989, can bedeferred under IRC section 59(e) and amortized over a period of 60 months on astraight line basis. The amortization claimed under IRC section 59(e) is notconsidered a tax preference item for alternative minimum tax purposes. The option to expense or capitalize domestic IDC is available to all taxpayers, bothindividuals and corporations, with one exception. Integrated oil companies can deductonly 70 percent of their domestic IDC currently. The remaining 30 percent must becapitalized and deducted ratably over 60 months, starting with the month in which thecosts are paid or incurred (IRC section 291(b)). Foreign IDC is capitalized, with onelimited exception for IDC incurred in the North Sea. In some cases, IDC must be capitalized. In a situation where one company owns alease, but for some reason, does not wish to expend funds to explore it, anothercompany may approach the first company with a farmout proposition. For example, the second company may propose that it will fund the drilling of the first test well inexchange for 50 percent of the leasehold interest. In this case, 50 percent of its drillingcosts must be capitalized to leasehold acquisition cost. However, if the farmoutagreement provides that the second company will receive 100 percent of the production until the cost of drilling is recovered, at which time its interest will drop tothe aforementioned 50 percent, the company is entitled to deduct 100 percent of itsexpended IDC. In another example, Company A has a lease of its own near or next to the lease ofCompany B. Company A may contribute an amount to Company B encouraging thedrilling of a test well (dry hole or bottom hole contribution). If Company B establishesthe probable productivity of the payer's lease, these payments must be capitalized tothe payer's lease and must be recognized as ordinary income by the payee. The Tax Reform Act of 1986 expanded the applicability of IDC as a tax preferenceitem for tax years beginning after December 31, 1986. IDC is a tax preference itemapplicable to all individuals and corporations in computing the alternative minimumtax. Prior to 1987, IDC was a tax preference item for individuals only. Thepreference for IDC is defined in IRC section 57(a)(2). It is equal to the amount bywhich the excess IDC exceeds 65 percent of net income of the taxpayer from all oil, gas, and geothermal properties for the taxable year. IRC section 57(a)(2)(B) shouldbe looked at for the definition of excess IDC. However, this area of concern willcease after 1992 with regard to independent producers and royalty owners. TheEnergy Policy Act of 1992 repealed the alternative minimum tax IDC preference itemfor independent producers and royalty owners, not integrated oil companies. Therepeal is effective for taxable years beginning after December 31, 1992.

In the examination of IDC, the two main items to note are the following:

1.Was a proper election to deduct IDC made?

2.Are the costs in fact intangible and not depreciable asset costs?

The classification of IDC claimed for offshore wells drilled from offshore platforms isvery technical. The determination of whether they are, in fact, capital in nature is mostdifficult. Therefore, petroleum engineering assistance should be requested.

Audit Techniques

Since IDC is a tax preference item for alternative minimum tax for taxable yearsbeginning before January 1, 1993, it is important to properly separate IDC from LOE. There may be very subtle differences. For instance, the costs relating to servicing awell, including pulling rods, acidizing, fracturing, and cleaning out, are LOE. The costof fracturing the production sands before production begins is IDC. To properlycategorize the expenditures, it is important to analyze the invoice or billing from thedrilling contractor or the operator to determine exactly what services or equipmentwere provided. If you are examining a working interest owner who is not theoperator, remember that you don't have to stop at the joint interest statement providedby the operator. You can inspect the original records in the operator's possession. The following are some suggested useful auditing techniques for IDC.

1.Determine if the taxpayer has made a proper election to deduct IDC as a currentexpense.

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 it was 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 C.B. 225 and Rev. Rul. 71-252, 1971-1 C.B. 146.

c.Consider the effect of an adjustment. Does the adjustment have taxsignificance, or would it be a mere rollover? Remember the timing of IDCdeduction could affect the net income limitation for percentage depletion underIRC section 613A.

5.Scan the depletion schedules to determine which newly acquired leases areproductive.

a.Have the drilling costs been shown as a deduction on the leases for the 50percent percentage depletion limitation?

b.Prepare a list of new productive leases from the depletion schedule.

6.From the list of new productive leases prepared, request the lease files on all newproductive leases, or on a selective basis if the number is large.

a.Review the lease files to determine if the taxpayer's ownership correspondswith the amount of TDC deducted. If not, why not? Is the deductionallowable?

b.Review assignments, correspondence, and related documents to determine ifthe taxpayer has drilled for its interest in the lease, and if the taxpayer iscarrying other owners.

c.If transactions are found, has the taxpayer handled them correctly? SeeRevenue Rulings 70-657, 1970-2 C.B. 70; 71-206, 1971-1 C.B. 105; and 77- 176, 1977-1 C.B. 77.7.Scan the producing lease account in the asset section of the ledger.

a.Note the leases that have been removed (credits).

b.Have the removed leases been reported as sales?

c.Should IDC be recaptured in accordance with IRC section 1254?

8.Allocate a reasonable amount of administrative overhead costs to IDC for taxpreference purposes before computing the minimum tax.

a.Usually, this can be done by allocating overhead based on direct departmentalcosts.

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.Verify that the taxpayer owned the entire working interest during the completepayout period. Entire ownership is required for the taxpayer to be allowed todeduct 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 taxunder IRC section 57 or recapture under IRC section 1254?

LEASE AND WELL EQUIPMENT

Lease and well equipment, also known as tangible equipment costs, is the equipmentand facilities used on the lease for the production of oil or gas. These items havepotential salvage value and are capital expenditures. The following are examples of costs associated with lease and well equipment.

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 truck turnaround pad and overflow pits at new tank battery.

DEPLETION

Oil and gas properties are wasting assets, since the amount of minerals in place arefinite. Once a property becomes producing, the taxpayer wants to recover itsleasehold costs. The Code allows the taxpayer to recover these costs through thedepletion deduction. There are two methods for computing depletion, cost andpercentage. The taxpayer must take the greater deduction of the two methods. Bothmethods are on a property-by-property basis. The cost depletion method is essentiallya units-of-production method. For the taxpayer to receive the benefit of a costdepletion deduction, the taxpayer must have basis available in the property. Thepercentage depletion deduction is based on a percentage (currently 15 percent) ofgross income from the property. IRC section 613A(c)(6), amended by the RevenueReconciliation Act of 1990, increases the percentage depletion with respect tomarginal production properties for tax years beginning after December 31, 1990. Theincrease is 15 percent plus 1 percentage point for each whole dollar that the referenceprice for crude oil for the immediately preceding calendar year is less than $20 perbarrel. The amount of the percentage depletion deduction is limited to 50 percent (or100 percent after 1990) of the net income of the property, performed on a property- by-property basis, and 65 percent of the taxpayer's taxable income. The allowabledepletion deduction is the greater of the two methods. A taxpayer must have an economic interest in the property to claim a deduction fordepletion, with the exception of production payments treated as loans and installmentbonuses under IRC section 636. The law further limits the taxpayers entitled to apercentage depletion deduction to entities that qualify as independent producers and certain royalty owners. There are special rules that apply to transfers of proven oil andgas properties. See the section entitled Transfers of Proven Properties for the rules. In determining whether to propose adjustments to depletion, the examiner should beaware of the intricacies of the depletion calculation. Will changing an incorrectlyclassified direct expense from one property to another, or changing an overheadmethod, result in a change to the 50 percent (or 100 percent) net income limitation onany properties? If so, is the change material enough to warrant the time involved? Onthe properties with the material change, will the taxpayer be allowed a cost depletiondeduction greater than the corrected percentage depletion deduction? Will alternativeminimum tax negate the entire adjustment to depletion? It should be noted thatalthough a large adjustment may be made to overhead or to a direct expense of aproperty for depletion purposes, the tax effect may be minimal. The adjustment(s) may not affect the properties which were limited by the 50 percent (or 100 percent) net income limitation or the properties may have a cost depletion deduction that wouldentitle them to a deduction close to the percentage depletion deduction for theproperty.

ECONOMIC INTEREST

A taxpayer has an economic interest when it has acquired any interest in a mineral inplace, by any form of legal relationship, and has vested rights to the income from theextraction of the mineral that is looked to for a return of capital. A person who has nocapital investment in the mineral deposit does not have an economic interest merelybecause the taxpayer gains an economic or monetary advantage from productionthrough a contractual relationship. The contractual right to purchase oil or gas after ithas been produced is an example of an economic advantage (Rev. Rul. 68-330, 1968-1C.B. 291).

Cost Depletion

The cost depletion deduction assures the owner of an oil and gas producing property atax deduction equal to the investment in the mineral property as the reserves aredepleted. Examiners need to become familiar with Treas. Reg. section 1.611-2(a) andsection 1.612-3(a) for computing cost depletion. The cost depletion deduction for a property is computed as follows:

OR

3-42Equation

ADJUSTED

BASIS OF

PROPERTY

UNITS SOLD DURING THE TAX YEAR

--------------------------------

UNITS SOLD REMAINING RECOVERABLE

DURING THE [+] RESERVES AT

TAX YEAR YEAR ENDCURRENTCOSTDEPLETIONDEDUCTION[X]

=

Equation

ADJUSTED BASIS OF THE PROPERTY UNITS SOLD CURRENT------------------------------------ [X] DURING THE = COSTUNITS SOLD REMAINING RECOVERABLE TAX YEAR DEPLETIONDURING THE [+] RESERVES AT DEDUCTIONTAX YEAR YEAR END

Units Sold

In the selection of a unit of mineral for depletion, preference shall be given to theprincipal or customary unit or units paid for in the products sold, such as barrels of oilor MCF for gas. Some taxpayers convert barrels of oil to MCF of gas, or gas tobarrels, by reference to the value of each. Thus, both oil and gas enter into thecalculation, although Treas. Reg. section 1.611-2(a) indicates only one should beused. This usually results in an equitable deduction. Any adjustment to the methodusually is small and insignificant. For a cash basis taxpayer, units sold includes only units for which payment wasreceived during the period. For an accrual basis taxpayer, the units sold shall bedetermined from the taxpayer's inventories kept in physical quantities and in a mannerconsistent with his or her method of inventory accounting under IRC section 471 orsection 472. No units should be included for which depletion was allowed in a priorperiod. If the taxpayer received prior period price adjustments, determine if the taxpayerincluded the barrels or MCF in the current period units sold for cost depletion. Ifthe taxpayer did include prior period price adjustments in the current period unitssold, exclude these units.

Adjusted Basis of Property

An allowable deduction for depletion (cost or percentage) will reduce the basis of aproperty, as determined under IRC section 1011, for the cost depletion computation. It should be noted that cost depletion is limited to the adjusted basis of the property, whereas percentage depletion can exceed it. The taxpayer should maintain accountswhich have accumulated all the capitalized costs and allowable depletion (percentageand cost) by property. If costs exceed the depletion reserve (accumulated depletion), the difference is the remaining basis. The effect of this is that an addition to capital ofany asset may be fully offset by previously allowed percentage depletion, so thatimmediately after a substantial capitalization, the taxpayer's remaining basis may bezero (Rev. Rul. 75-451, 1975-2 C.B. 330 and Treas. Reg. S1.614-6(a)(3), Example 1).

Reserves

The reserves to be included in the calculation of cost depletion for tax purposesinclude proved and probable reserves in accordance with Treas. Reg. section 1.611- 2(c). Regulations indicate probable or prospective reserves are to be included only if they are extensions of known deposits or are new bodies of mineral whose existence isindicated by a high degree of probability. Examining officers should be cognizant thattaxpayers may have different categories with similar definitions. Some additionalinformation can be found in the Journal of Petroleum Technology, May 1987, pages577-78.

Cost Depletion on Wildcat Acreage

If a taxpayer (landowner) receives a lease bonus on wildcat acreage and claims costdepletion equal to 100 percent of its cost, this has the effect of claiming that theminerals are worthless as they supposedly will produce no future income. Worthlessness must be proven by an identifiable event, and in this case, no such eventhas occurred. Further, it is assumed that the lease itself has value or the lessee wouldnot have paid the bonus. Therefore, cost depletion should not be allowed unless it ispossible to make a reasonable estimate of future income and that estimated income isnot zero. However, for a contrary decision, see Collums v. United States, 480 F. Supp. 864, 45 A.F.T.R. 2d 80-751 (D Wyo. 1979), with respect to which no action ondecision has been issued.

PERCENTAGE DEPLETION

Independent Producer

An independent producer, as defined by IRC section 613A(d)(2), is a producer whodoes not have more than $5 million in retail sales of oil or gas in a year (a retailer) andwho does not refine more than 50,000 barrels of crude oil on any day during the year(a refiner). No percentage depletion is allowed to a taxpayer to the extent its averagedaily production of domestic crude oil and domestic natural gas exceeds 1,000 barrelsof oil per day or 6,000 cubic feet of gas per day. To determine the taxpayer's depletable oil quantity, the taxpayer's average daily oil andgas production must be determined. A taxpayers average daily oil production andaverage daily gas production is determined by dividing its total crude oil productionand total gas production by the number of days in that tax year, excluding oil and gasthat result from a secondary or tertiary process, gas sold under a fixed contract, regulated natural gas, and production from a proven property transferred after 1974(secondary and tertiary properties may be transferred and still qualify for percentagedepletion). Remove the taxpayer's average daily secondary and tertiary productionand the number of barrels which the taxpayer elects to convert from natural gas to oil(1 barrel equals 6 MCF) from the tentative oil quantity (1,000 barrels). Thus thetaxpayer's depletable oil quantity is the portion of the average daily barrels within the1,000 barrel limit (secondary and tertiary recovery barrels, gas converted to oil, andthe balance of the oil barrels).

For purposes of applying the 1,000 barrel limitation, all members of a controlled groupare treated as one taxpayer. Also, a family group, which consists of an individual, spouse, and minor children, will be allowed only one 1,000 barrel limitation.

Transfers of Proven Properties

The Revenue Reconciliation Act of 1990, repealed the transfer limitation rules. Percentage depletion is now allowable on transferred proven oil and gas properties fortransfers after October 11, 1990. This repeal is applicable to all domestic oil and gasproducing properties. An oil and gas property is proven if, at the time of the transfer, all of the followingconditions exist: 1.Any oil and gas has been produced from a mineral deposit which underlies suchproperty (production from the deposit may not necessarily have been from theproperty); 2.Prospecting, exploration, or discovery work indicates it is probable that theproperty will have gross income from oil or gas from such deposit sufficient tojustify development; and3.The fair market value of the property is 50 percent or more of the fair market valueof the property, minus actual expenses of the transferee for equipment and IDC, atthe time of the first production from the property subsequent to transfer and beforethe transferee transfers its interest. All three provisions, cited above, of Treas. Reg. section 1.613A-7(p) must be satisfiedfor the property to be proven property. If this issue is unagreed, an engineer referralmust be made to determine the fair market value of the property.

Gross Income from the Property

Gross income per the tax return and gross income per the depletion schedule willgenerally not be the same. various adjustments must be made to determine grossdepletable income. Examples of oil and gas revenues per the general ledger may begas sales, oil sales, condensate sales, plant products, royalty gas sales, royalty oil sales, and royalty condensate sales. it should be noted the plant products are not grossdepletable income. Examples of accounts not included in depletable income are plantoperating income (for example, propane, butane, and ethane sales), marketing income, truck rentals, pipeline fees, and consulting fees. This list is not all inclusive, but is tobe used as a reference. Only 100 percent of the proceeds of actual sales of oil and gas, not production, are subject to depletion. The proceeds, subject to depletion, generallyare limited to the representative market or field price of sales in the immediate vicinity of the well. Gross income from the property includes any production or severancetaxes which are the responsibility of the seller.

There are several adjustments to book income to determine income subject todepletion:

1.Transportation costs: These costs must be isolated from production income. Theyare not subject to depletion. (Treas. Reg. section 1.613-3(a) and Rev. Rul. 75-6,1975-1 C.B. 178.)

2.Lease Bonus Exclusion: Gross income is reduced by a portion of the bonuspayment to arrive at depletable income. (Rev. Rul. 79-73, 1979-1 C.B. 218; Rev.

3.Royalty Income: If paid by the working interest owner, it must be excluded fromdepletable income.

4.Advanced Royalties: Gross income is reduced by a portion of the advancedroyalty payment to arrive at depletable income.

5.Delay Rentals: When received by the landowner, delay rentals are not paymentsfor production of oil and gas and are not subject to depletion.

6.Taxes: The amount received by a producer is usually net of production andseverance taxes; this amount received generally needs to be grossed up by theamount of the taxes for depletion purposes. There are instances in which there is no determinable representative market or fieldprice. In these instances, it is necessary to make a determination of gross income fromthe property by studying the data. These situations have given rise to several courtcases. The following court decisions address the determination of gross income:

1.Weinert v. Commissioner, 294 F.2d 750 (5th Cir. 1961), 8 A.F.T.R. 2d 5417, 61-2U.S.T.C. 81,606.2.Shamrock Oil and Gas v. Commissioner, 346 F.2d 377 (5th Cir. 1965).

3.Mountain Fuel Supply Co. v. United States, 449 F.2d 816 (10th Cir. 1971), 28A.F.T.R. 2d 71-5833, 71-2 U.S.T.C. 87,650, cert. denied, 405 U.S. 989.4.Exxon Corporation and Affiliated Companies v. Commissioner, 102 T.C., No. 33(1994). If the depletion claimed for gas production is significant and there is no determinablerepresentative market or field pricer examining officers should request the assistanceof an engineer.

Income Flow Sheet for DepletionPer 1120 Tax ReturnPer General LedgerDeple-

tionAdjustment Due toDepletion DeductionLine 1 Gross Receipts

Line 7 Gross

RoyaltiesLease Income

Gas Sales -------->

Oil Sales -------->

Condensate Sales-->

Plant ProductsPlant Operating Inc

Propane

Butane

EthaneRoyalty

Gas Sales -------->

Oil Sales -------->

Condensate Sales-->

Marketing IncomeTruck RentalsPipeline FeesConsulting FeesYesYesYesNANANANAYesYesYesNANANANATransportation -

Rev. Rul. 75-6,

1975-1 C.B. 178

Treas. Reg. section

1.613-3(a)

Bonus -

Rev. Rul. 79-73,

1979-1 C.B. 218

Rev. Rul. 81-266

1981-2 C.B. 139

Helvering v.

Twin BellAdvance RoyaltiesDelay RentalsGross up TP's

interest for

severance tax if it

is not already the

gross amount.

NET INCOME OF THE PROPERTY

Percentage depletion is computed on a property-by-property basis. Examining officersshould become familiar with the 'property concept' before attempting to determinetaxable income from the property. Taxable income from the property is important because the percentage depletiondeduction is limited to a percentage of taxable income from the property, computedwithout regard to depletion allowance, per IRC section 613(a). For taxable yearsbeginning before January 1, 1991, the net income limitation is 50 percent. For taxableyears beginning after December 31, 1990, the net income limitation has been increasedfrom 50 percent to 100 percent of net taxable income. The increased limitation, 100percent, is applicable only to oil and gas properties.

EXPENSES OF THE PROPERTY

The taxpayer will claim various expenses (for example, lease operating, severancetaxes, production taxes, depreciation, overhead, etc.) to compute each property's net income. These expenses will be directly attributable to the property or the taxpayerwill be required to use an allocation method. See the section entitled OverheadAllocation below for a discussion of allocation methods with regard to depletion. A taxpayer can manipulate the percentage depletion deduction. This can beaccomplished by reallocating direct expenses between properties, manipulating the netincome limitation of each property subject to the limitation. When examiningpercentage depletion, the income and expenses of each property should have acorrelation to the other properties' income and expenses. If not, ask for an explanationand sample some of the invoices associated with the properties in question. There maybe a plausible explanation such as the well was in an area that is more costly toproduce, expensive workover cost, etc.

OVERHEAD ALLOCATION

Expenses must be separated between direct and indirect. Direct expenses, as we havealready learned, are easily apportioned to their specific activity or property. Indirectexpenses, also known as overhead, are those not directly attributable to any specificactivity or property. Some examples of indirect expenses are supervisory salaries, utilities, rent, depreciation of office equipment, office supplies, employee benefitprograms, marketing expenses, general and administrative expenses, accountingdepartment, land department, etc. Each separate activity should draw a portion of the overhead that is incurred. In theoil and gas business, a taxpayer may have a land and exploration department whichdevelops nonproducing properties. The taxpayer may also be the operator for the jointinterest owners and, therefore, bear additional overhead and administrative costs toaccount to the joint interest owners. The overhead associated with the operation ofthe joint venture cannot be allocated to the production of oil and gas. It is a separateactivity and should draw an appropriate portion of overhead. The overhead allocationmay have to be accomplished in several layers, depending on the complexity anddiversity of the company. The method of allocation does not have to be the same foreach layer as long as it is reasonable and the deductible expenditures have been fairlyapportioned (Occidental Petroleum Corp. v. Commissioner, 55 T.C. 115 (1970)). Ifthe taxpayer has nonproducing oil and gas properties, the first layer of allocationcannot be based on gross income. While the burden of proof is on the taxpayer, as apractical matter the Internal Revenue Service must be prepared to demonstrate specificbias in the taxpayer's method of overhead allocation.

The formulas for Direct Expense Allocations and Gross Income Allocations are asfollows:

Direct Expense Allocations Formula

DIRECT EXPENSE ALLOCATION FORMULA:

ExpenseDirect Expenses

AllocationPer The Property

Overhead = ---------------------

RatioTotal Direct Expenses

(All Properties)Gross Income Allocations

GROSS INCOME ALLOCATION FORMULA:

Gross IncomeGross Income

AllocationPer The Property

Ratio = ---------------------

Total Gross Income

(All Properties)

Audit Techniques

In the initial interview, examiners should determine how the taxpayer allocatesoverhead. Also, one should determine if the taxpayer has an economic interest in theproperty. Scan the properties to make sure that overhead is allocated to bothproducing and nonproducing properties. In addition, the properties should bescrutinized to ensure that all business activities are receiving their share of overheadincluding investments, production, refining, etc. Interest expense paid on moneyborrowed for operating capital is an overhead item which should be capitalized as anaccumulating production cost subject to the rules of IRC section 263A. The taxpayershould net interest expense to the extent of interest income before allocation.

INFORMATION REQUIRED TO COMPUTE DEPLETION ALLOWANCE

There is certain information that examiners must secure before the maximum allowabledepletion can be computed. Below is the list of information that is needed:

1.What is the taxpayer's average daily production of domestic crude oil and how wasit computed (IRC section 613A(c)(2))?

2.Is the taxpayer required to share the tentative depletable oil quantity with relatedentities or family members (IRC section 613A(c)(3) and IRC section 613A(c)(8))?

3.If the answer to question 2 is yes, determine the taxpayer's individual share oftentative oil quantity under IRC section 613A(c)(3) and IRC section 613(c)(8).

4.Which properties were producing under regulated natural gas and natural gassold under a fixed price contract?

5.Which properties are producing as a result of secondary and tertiary activities?

6.Which properties were producing as proven properties (IRC section613A(c)(9))?

7.Which purchased properties qualify for depletion under exceptions to the generalrules regarding transfers?

8.Is the percentage depletion limited to 65 percent of adjusted taxable income?

9.Have overhead expenses been allocated to the properties for percentage depletionpurposes?

10.Are any of the properties limited to 50 (100) percent of net income for percentagedepletion?

11.Is the taxpayer a refiner or retailer (IRC section 613A(d)(2) or IRC section613A(d)(4))? It is imperative that examiners tie down gross income for computing depletion. Below are suggested audit techniques for establishing gross income for depletionpurposes:

1.Gross income for depletion should be reduced by transportation costs. Determine how the taxpayer is handling transportation costs.

a.Inspect posted price bulletin. If the price paid is wellhead price, it does notinclude transportation.

b.If a spot price is paid, look to the contract or the prices paid per the postedprice bulletin for the general vicinity.

c.If the price the taxpayer received is higher, the difference could betransportation charges. If they are transportation charges, back them outbefore computing depletable income.

2.If the taxpayer is an operator of any properties, determine how the taxpayerhandles the income received for operating the property for depletion purposes.

a.The taxpayer should treat the income as a separate activity which isallocated a share of the taxpayer's overhead.

b.The taxpayer should not reduce expenses or increase income of theproperties it operates by the amount of the operator income received.

c.The taxpayer should not reduce the general overhead allocated to theproperties by the amount of operator income received.

3.The following amounts are to be treated as ordinary income not subject topercentage depletion:

a.Lease bonuses, royalties paid in advance, and minimum and shut inroyalties received or accrued after August 16, 1986. Prior to this date, these items were allowed percentage depletion.

b.Delay rentals.

c.Ad valorem taxes paid by the lessee for the lessor.

ALTERNATIVE MINIMUM TAX

There are two tax preference items which are applicable to oil and gas. They arepercentage depletion and IDC. These tax preference items are applicable toindependent producers and royalty owners through taxable years beginning beforeJanuary 1, 1993. The Energy Policy Act of 1992 repealed both alternative minimumtax preference items, percentage depletion and IDC, for independent producers androyalty owners, not integrated oil companies. The repeal is effective for taxable yearsbeginning after December 31, 1992.

Percentage Depletion

The tax preference item for depletion is the excess of percentage depletion over theadjusted basis of the depletable interest at the end of the taxable period.

Intangible Drilling Costs

The excess of IDC, in connection with oil and gas wells that are expensed under IRCsection 263(c), over the amount which would have been allowable if the costs hadbeen capitalized and a straight line recovery of IDC had been used with respect tothese costs is the tax preference item. As previously discussed, the amortization claimed under the secondary election set outin IRC section 59(e) is not considered a tax preference item for alternative minimumtax purposes.

Alternative Tax Energy Preference Deduction The Revenue Reconciliation Act of 1990 made significant changes to allow a specialenergy deduction in computing the alternative minimum tax. The act added IRCsection 56(h) creating the new deduction applicable to tax years beginning afterDecember 31, 1990. This deduction, available for the taxable years of 1990, 1991, and 1992, may not be claimed by integrated oil companies. The Energy Policy Act of1992 repealed the deduction effective for taxable years beginning after December 31,1992. The deduction is an amount equal to the sum of: 1.75 percent of the portion of the IDC preference attributable to qualifiedexploratory costs; 2.15 percent of the portion of the IDC preference not attributable to qualifiedexploratory costs; and3.50 percent of the portion of the percentage depletion preference (as determinedunder IRC section 57(a)(1)) which is attributable to marginal production of oil andgas. The alternative tax energy preference deduction is limited to 40 percent of thealternative minimum taxable income determined without regard to either the specialenergy deduction or the alternative tax net operating loss deduction. Any amountlimited by the 40 percent is not allowable as a carry forward to another taxable year. Qualified Exploratory Costs The new Code section defines qualified exploratory costs as IDC of a taxpayer, other than an integrated oil company, that the taxpayer may elect to deduct as IDCunder IRC section 263(c), and are paid or incurred in connection with the drilling of anexploratory well located in the United States. The qualified exploratory costs do not include any costs paid or incurred inconstructing, acquiring, transporting, erecting, or installing an offshore platform, orwith respect to the drilling of a well from an offshore platform unless it is the first wellthat penetrates a reservoir. 3-52  Exploratory Well An exploratory well is any of the following oil or gas wells. 1.An oil or gas well that is completed (or if not completed, with respect to which thedrilling operations cease) before the completion of any other well that is locatedwithin 1.25 miles of the well, and is capable of production in commercialquantities. 2.An oil or gas well that is not described in (1) but which has a total depth that is atleast 800 feet below the deepest completion depth of any well within 1.25 milesthat is capable of production in commercial quantities. 3.An oil or gas well capable of production in commercial quantities that is notdescribed in (1) or (2) but which is completed into a new reservoir, except that thisshall not apply to a gas well if the gas is produced (or will be produced) fromDevonian shale, coal seams, or a tight formation. An engineers certificate must be obtained from the operator by the taxpayer who hasclaimed the deduction to ensure that the well qualifies and will be treated as anexploratory well. Rev. Proc. 92-62, 1992-2 C.B. 240, requires the petroleumengineer, that certifies the well, be duly registered, licensed, or certified in any state. Marginal Production Marginal production includes domestic oil and gas production from the following. 1.A stripper well property which is property that has an average daily production of15 barrel equivalents or less per producing oil or gas well in any calendar year. 2.A property of which substantially all of the production is heavy oil (that is, crudeoil which had a weighted average gravity of 20 degrees API or less at 60 degreesFahrenheit). The percentage depletion preference attributable to a marginal production property isbased on the percentage depletion preference that relates specifically to the marginalwells. The taxpayer must determine what wells produce percentage depletion inexcess of basis. If only non-marginal wells produce percentage depletion in excess ofbasis, there is no marginal depletion preference. If the taxpayer has a property that hasboth marginal and non-marginal wells, the property's basis must be allocated on areasonable basis between the two. 3-53  Phase Out of the Deduction The special energy deduction is phased out in taxable years that follow the calendaryears in which the price of oil exceeds a certain level. The deduction is completelyphased out if the price of oil for the calendar year is $6 per barrel more than $28 perbarrel (adjusted for inflation). The preference deduction is ratably reduced when theprice of oil for the calendar year exceeds $28 per barrel as adjusted for inflation, in anamount less than $6 per barrel. For example, if in a year the price exceeds the adjustedbase level by $3, then the deduction would be reduced by 50 percent ($3 over $6). Audit Techniques Depletion If the taxpayer is claiming percentage depletion, determine whether the taxpayer has apreference item for alternative minimum tax. IRC section 57(a)(1) states that withrespect to each property, the excess of percentage depletion over the adjusted basis ofthe depletable interest at the end of the taxable year, is a tax preference item. Theadjusted basis of the property is determined without regard to the depletion deductionfor the taxable year. The taxpayer must supply verification of the adjusted basis of the depletable propertyat the beginning of the year. Most taxpayers include the adjusted basis of the propertyin their depletion schedule. If the taxpayer is unable to provide this verification, thenall percentage depletion will be considered as a tax preference item. Also, ensure thatthe taxpayer has not included the depreciable basis on the depletion schedule. Intangible Drilling Costs If the taxpayer has made an election to expense IDC, then the excess IDC will be a taxpreference item for purposes of alternative minimum tax under IRC section 57(a)(2). The excess IDC is the excess of the intangible drilling and development costs, inconnection with oil and gas wells that are expensed under IRC section 263(c), over theamount which would have been allowable if the costs had been capitalized and straightline recovery of intangibles had been used with respect to these costs. The straightline recovery is either amortization over 120 months or the cost depletion method forthose wells, whichever is greater. The amount of the tax preference for excess IDC is the amount by which the excessIDC is greater than 65 percent of the net income of the taxpayer from the oil and gasproperties. To determine the amount of tax preference for excess IDC, the followingthree steps must be followed: 3-54  1.Compute EXCESS IDC. a.Compute straight line recovery of IDC. Taxpayers may choose one of thefollowing methods: 1)120 MONTH RULE. Months of Production Straight-Line--------------------- [X] IDC = Amortization 120 Months Of IDC 2)COST METHOD. Months of Production Straight-Line----------------------- [X] IDC = AmortizationUnits Sold (+) Year End Of IDC Reserves b.Compute Excess IDC as Follows. IDC Claimed on Return (Do Not Include IDC on Dry Holes) () Straight-line Recovery of IDC-------------------------------------------- Excess IDC [On a Well-by-Well Basis] ============================================ 2.Compute NET INCOME OFFSET as Follows. Gross Income from the Property() Expenses (Including IDC Per Return) -------------------------------------- Net Income from the Property(x) 65 Percent-------------------------------------- Net Income Offset================= 3. Compute TAX PREFERENCE AMOUNT as Follows. Excess IDC (As Computed Above) () Net Income Offset (As Computed Above) ----------------------------------------- Tax Preference Amount===================== 3-55  ALTERNATIVE TAX ENERGY PREFERENCE DEDUCTION Examiners should ensure that the amount claimed as IDC associated with anexploratory well is equivalent to and deductible as IDC under IRC section 263(c). A map depicting the location of all wells should be reviewed if the well is certifiedbecause its location is at least 1.25 miles from a commercially productive well. Themap should depict all wells regardless of who actually operates them. Examinersshould consider obtaining and reviewing maps prepared by state jurisdictional agenciesand commercial map companies for verification of the maps submitted by the taxpayer. A well is presumed to be capable of production in commercial quantities at the timethat it has been completed with the installation of a Christmas tree, or othermechanism to regulate the flow of oil or gas. A good source of information can befound in the service company's bill to the operator for the installation of equipmentassociated with preparing a well for production. This bill would include costs for thelabor crew and equipment for installing the Christmas tree and flow lines, levelingthe tank pad, and setting the tank, etc. Examiners should also obtain and review the reports filed with the state or federalregulatory agency for each particular state. Examples of reports could be a drillingpermit, well completion or plugging report, test reports, production reports, andrecompletion reports. If the taxpayer is claiming that the well is at least 800 feet below the deepestcompletion depth of any well within 1.25 miles and is capable of production incommercial quantities or the well is completed in a new reservoir, well logs andseismic maps should be reviewed. These logs and maps will assist in determining thedepth and reservoir delineation. Exploratory wells do not include a well drilled for the purpose of supportingproduction from another well or wells. This would include wells drilled solely for thepurpose of injecting gas, water, steam, or air. Wells drilled for water disposal or watersupply would not qualify. Stratigraphic test wells are wells drilled for the purpose ofobtaining information specific to a geologic condition and would not qualify. Stratigraphic wells are drilled without the intention of being completed for theproduction of hydrocarbons. SELF-EMPLOYMENT INCOME Nonoperated interests are generally considered passive income and not subject to self- employment tax. See Rev. Rul. 69-355, 1969-1 C.B. 65. However, when anonoperated interest is obtained as a result of personal services and the value is nottaxed when received, self-employment tax is applicable. Overriding royalty interests (ORRI), retained in working interests, are routinelyacquired for use in a taxpayer's trade or business. An ORRI used in the trade or 3-56  business is considered a part of that business for purposes of computing self- employment tax. Working interests in an oil and gas venture are considered to be engaged in the activeconduct of a trade or business and are subject to self-employment tax. The taxpayerdoes not have to be the operator of the property to be subject to self-employment tax. Minority ownership in oil and gas working interests are governed by a joint operatingagreement that is agreed to by the working interest owners. This agreement creates apartnership for statutory purposes outside of IRC subchapter K. As a result, the oiland gas income constitutes self-employment income under IRC section 1402. SeeRev. Rul. 58-166, 1958-1 C.B. 324, and Frances Cokes v. Commissioner, 91 T.C. 222(1988). A limited partner may not treat any loss claimed on its partnership return as a net lossfrom self-employment because the distributive share on any item of income or loss of alimited partner is excludable from the computation of net earnings from self- employment. See IRC section 1402(a)(12) and Mammoth Lake Project v. Commissioner, 61 T.C.M. 1630. Examiners need to scrutinize the income and losses reported on Schedule SE of Form1040 and determine that all types are properly classified as self-employment income orlosses. Income and expenses from a joint venture will be recorded on Schedule C. The Service is not following the holding in Hendrickson v. Commissioner, T.C. Memo1987-566. See instead Frances Cokes v. Commissioner, 91 T.C. 222 (1988). PASSIVE ACTIVITY LOSS LIMITATION Before examiners even consider the application of IRC section 469, each activity mustbe considered for at risk under IRC section 465. Any losses limited due to the at riskrules will be allowed as a deduction in the next succeeding year, provided there isadditional at risk basis of property at the end of that year. If a loss is disallowed underIRC section 465, the passive loss rules will not apply. IRC section 469(a) denies any net losses or tax credits from passive activities. Lossesand credits from passive activities may only reduce income from other passiveactivities. The excess is carried forward to subsequent years to offset passive activityincome arising in those years. A special exception permits closely held C-Corporationsto deduct passive losses against net active business income, but not against portfolioincome. The passive activity loss limitation is applied after the percentage depletion limitations. The portion of the percentage depletion deduction carried over to a subsequent yeardue to the 65 percent of taxable income limitation is allowed without regard to theapplication of IRC section 469 in that year. 3-57  All activities which are passive will be used in the computation of the allowed passiveactivity loss on Form 8582 for individuals, estates and trusts or Form 8810 for closely- held and personal service corporations. Taxpayers may attempt to misclassify activeincome as passive and passive losses as active. Therefore, examiners should reviewthe activities listed on Forms 8582 or 8810 to determine if the taxpayer properlyclassified the interest. Oil and Gas Activities A passive activity does not include any working interest, operating or nonoperating, held at any time during a taxable year in any oil or gas property which does not limitthe liability of the taxpayer with respect to such interest regardless of whether thetaxpayer would otherwise be treated as materially participating in the activity of theproperty. Qualifying working interests are determined on a well-by-well basis ratherthan property-by-property basis. Private contractual rights which provide protectionfrom economic loss through indemnification agreements, stop loss agreements, turnkey contracts, and insurance are not considered limitations on a taxpayer's liabilityfor IRC section 469. An interest in an activity as a limited partner will be considered passive. Income fromoil and gas activities that do not qualify for the working interest exemption may stillqualify under the material participation requirement as trade or business income. Thelook back rules are required when the working interest was excluded from the passiveloss rules by the reason of the working interest exception rather than the materialparticipation criteria (IRC section 469(c)(3)(B) and Treas. Reg. section 1.469- 2(c)(6)). Portfolio Income Portfolio income is defined to include gross income from interest, dividends, annuities, or royalties not derived in the ordinary course of a trade or business. The gain or lossfrom the disposition of such property that produces such income is also consideredportfolio income. Oil and gas royalties, net profits interests and overriding royalties will generally beconsidered portfolio income. But there are two situations set out in the regulationsthat exempt royalties as portfolio income. Treas. Reg. section 1.469-2T(c)(3)(iii)(B) provides active income treatment forroyalties derived in the ordinary course of a trade or business. This exception does notapply to a taxpayer who is not a dealer in royalties. Treas. Reg. section 1.469-2T(c)(3)(ii)(G) requires the income to be identified by theCommissioner as income derived in a trade or business. The taxpayer must request aruling to have the royalties characterized as trade or business income. Industrypublications suggest that taxpayers should request a ruling to treat oil and gas royalties 3-58  as nonpassive income derived in a trade or business. Until, or if ever, theCommissioner expands the regulations to include certain oil and gas royalties asbusiness income, oil and gas royalties are to be included as portfolio income. The determination of whether royalties are portfolio income is made at the entity levelin the case of pass through entities, such as limited partnerships and S Corporations. 3-59  This page intentionally left blank.  Exhibit 3-1 Forms Required to be Filed with the Texas Railroad Commission Forms P-1, P-2, andThese Texas Railroad Commission forms are the producer's monthlyP-1Breport of oil wells and gas wells. They identify the field, lease, wells, and the amount of production by month from each well. They alsoshow the amount of oil or gas on hand at the beginning of each monthand the amount removed from the property. This report is preparedin-house and is only as reliable as the operator's books and records. Form W-1A Texas Railroad Commission form which must be filed by theoperator to receive a permit to drill, deepen, plug back, or reenter awell. It can be helpful in determining the operator's intent regarding aprospect, or an existing well. Form W-2A Texas Railroad Commission form which may be used to report oilwell potential test results, well completion, or well recompletionresults. It is filed by the operator and certified by a well tester. Thisreport can be helpful in providing background information about thewell's condition. Form W-3A Texas Railroad Commission form which is used to report theplugging and abandonment of a well. It is filed by the operator andcertified by the cementing company. It can be useful in verifyingwhen a well can be written off as a dry hole. In other states it may be necessary to contact the appropriate agency to obtain the requiredforms. 3-61  This page intentionally left blank.  Chapter 4FINANCIAL PRODUCTS POTENTIAL AREA OF CONCERN RELATED TO OIL AND GAS Due to the changing facets of the oil and gas industry, the industry has expanded itsactivities into the world of financial products. As a result of the volatility of prices ofbarrels of oil and MCFs of gas, the industry has entered hedging transactions to reducethe risk undertaken. This section of the MSSP guide is intended solely to introducethe energy markets, the vehicles used to participate, and the participants in themarkets. Examining officers should refer to IRM 4232.8:(11)00, Risk Management, for suggested examination techniques relating to financial products. ENERGY MARKETS AND THE PARTICIPANTS The oil market consists of three types of markets: cash market, forward market, andthe futures market. The cash market, also known as the physical or spot market, iswhere the actual physical oil is bought and sold through individual deals. The forwardmarket is where the oil is bought and sold between two parties with delivery takingplace at a future date. The futures market trades futures contracts and options onfuture contracts. Cash Market The cash market is where the physical oil is bought and sold through individual dealsmade between buyers and sellers which usually call for delivery within 30 days. Thismarket is global in nature and is made up of major international oil companies, nationaloil companies, fully integrated oil companies, independents, refiners, marketers, distributors, and traders. There are cash markets generally for all types of crude oilsuch as West Texas Intermediate, Brent (from the United Kingdom North Sea), andDubai. The major refineries produce gasoline, aviation fuel, distillate, and residual fueloil. A potential issue associated with physical transactions in the cash market is the use ofa consistent identification method for positions closed. Some taxpayers matchselected futures or physical contracts using a specific identification method tominimize gain reporting or to maximize losses, while matching othertransactions on the FIFO basis. Taxpayers must use the first in, first out methodsimilar to that described in Treas. Reg. section 1.1012-1(c), unless adequate recordsare kept on a consistent basis identifying inventory under another acceptable method. 4-1  Types of Physical Transactions Alternative Delivery Procedure. An Alternative Delivery Procedure (ADP) isavailable to buyers and sellers of New York Mercantile Exchange (NYMEX) contractsthat have been matched by the exchange subsequent to the termination of the contract. Deliveries of NYMEX crude oil futures require the delivery of West TexasIntermediate, F.O.B., Cushing, Oklahoma. Deliveries of heating oil and gasoline aremade F.O.B., New York Harbor. With an ADP, the buyer and seller agree toconsummate delivery under terms different from those prescribed in the NYMEXspecifications. An ADP can take place immediately after two parties have beenmatched for delivery by the NYMEX. In ADP transactions, the NYMEX and clearingfirms are released from all liabilities related to the delivery negotiated between theparties. A Notice of Intention must be submitted to the NYMEX by the partiesinvolved in the ADP. Once a futures contract has been terminated through the delivery process, brokeragestatements generally are not issued to record the sale, exchange, or carrying ofphysical commodities. The record keeping on physical transactions is generally doneby the taxpayer, rather than a third party. Thus, it becomes difficult to trace and verifyphysical commodity transactions. Warehouse receipts for physical transactions aregenerally issued in bearer form. Exchange of Futures for Physicals. An exchange of futures for physicals (EFP) is atransaction in which a buyer or seller may exchange a futures position for a cashposition of equal quantity by submitting a notice to the exchange. The price of theexchanged futures position, the quantity of the futures and cash commodity to beexchanged, the price of the cash commodity, and other terms are privately negotiatedby the parties and are not executed in an exchange or on a board of trade. EFP transactions are an exception to the general prohibition contained in theCommodity Exchange Act against certain noncompetitive and prearrangedtransactions in commodity futures contracts. The Commodity Exchange Act placesresponsibility on the commodity exchanges for establishing rules governing EFPs. EFPs serve an important function for commercial market users by providing a meansof pricing a cash transaction or making or taking delivery on their futurescommitments outside the normal exchange delivery system. This allows them to offsetexchange positions through privately negotiated transactions. EFPs in energy contracts are often used to control location and timing of contractsbecause of the transportation costs involved. A second major advantage of EFPs isthe ability for a firm to choose a party willing to take the opposite side of thetransaction, or instruct its broker to locate a suitable trading partner. An EFP allows, for example, a major oil company to be sure that the other side is financially able tohandle the transaction. It also ensures the company that the entity is one with which ithas an established supplier/customer relationship. Specifically, the buyer candetermine whether the seller is able to fulfill its delivery obligation, and the seller canevaluate the buyer's ability to take delivery. An EFP also ensures that the buyer will beable to match the delivery with the trade size at one location from one opposite party. 4-2  1.NYMEX Rules New York Mercantile Exchange Rule 6.21 governs EFP transactions. EFPs canbe negotiated at the time a particular energy futures contract trades or until 2 p.m. of the business day following the termination of trading in an expired futurescontract. After both parties to an EFP agree to such a transaction, the NYMEXmust be notified. An EFP is initially reported on a pit card which is a card usedby floor traders or members of the NYMEX to record transactions. All NYMEXrecords identify the trade as an EFP, but the trade will be handled as any otherfutures position. The EFP is cleared in accordance with normal procedures andidentified and recorded as an EFP by NYMEX (the Exchange) and clearingmembers involved. NYMEX rules require that each seller and buyer satisfy the Exchange that the EFPis bona fide. NYMEX rules also ascertain that the clearing members shall obtainall documentary evidence and make that evidence available to the Exchange attheir request. NYMEX requires that a clearing member submit a Form EFP-1, which documents and certifies the EFP as bona fide, to the clearing department. AForm EFP-2, which documents the actual transfer of possession of the cashcommodity, must be submitted to the Exchange's Compliance Department within 5business days after the physical delivery has occurred. 2.CFTC Position Section 4c(a) of the Commodity Exchange Act prohibits wash sales, cross trades, accommodation trades, fictitious sales, and transactions that cause prices to bereported, registered, or recorded that are not true and bona fide. However, section4c(a) provides a specific exception for EFPs. It states, Nothing in this sectionshall be construed to prevent the exchange of futures in connection with cashcommodity transactions or futures for cash commodities, or transfer trades oroffice trades if made in accordance with board of trade rules applying to suchtransactions and such rules shall have been approved by the Commission. The Commodity Futures Trading Commission (CFTC) Division of Trading andMarkets Report on Exchanges for Physicals has indicated that three essentialelements must exist in order for an EFP to be considered a bona fide EFP eligiblefor the statutory exception. These elements are as follows: a.There must be, both, a physical (cash) transaction and a futures transactionwhich are integrally related. b.The physical commodity contract must provide for a transfer of ownership ofthe physical commodity to the cash buyer upon performance of the terms of thecontract, with delivery to take place within a reasonable period of timethereafter; in accordance with the prevailing physical market practice. Actualdelivery need not take place if the selling party offsets the obligation by othermeans. 4-3  c.There must be separate parties to the EFP. The accounts involved must havedifferent beneficial ownership or be under separate control. Two situations exist which the CFTC believes should not be considered bona fideEFP transactions. First, a transaction which fails to comply with the conditions ofthe section 4c(a) exception or with the exchange rules governing the transactionwould be prohibited, even if it were characterized as an EFP by the parties to thetransaction and cleared by the Exchange. Second, a transaction that appears tocomply with section 4c(a) and any applicable exchange rules, but is intended toaccomplish some illegal purpose, would be prohibited as falling outside the scopeof the exception provided by section 4c(a). In addition to the three essential elements described above, the CFTC included fiveadditional items that an exchange or board of trade should consider whenevaluating EFP transactions. The following are the five items: a.The degree of price correlation between the cash component and the futurescontract. b.The prices of the futures and cash legs of the EFP and their relationship to theprevailing prices in either market. c.Whether the seller has possession, the right to possession, or the right to futurepossession of the cash commodity prior to an EFP. d.The cash seller's ability to perform on the delivery obligation in the absence ofprior possession of the cash commodity. e.Whether the cash buyer acquires title to the cash commodity. Pricing oil based on the closing of a futures contract has been found in numerouscases. If a taxpayer engages in EFPs, examiners should contact a commodityspecialist and/or the Petroleum Industry Program for assistance. Swap of Physical Commodity. A swap is a transaction in which one grade orlocation of crude oil or other production is swapped for another grade or location. This is known as a commodity swap. A refiner may arrange a swap of one grade ofcrude for another to fulfill its changing refining needs if it can locate a willing oppositeparty. A location swap can be used to obtain crude oil in the desired locationpermitting a refiner to avoid transportation costs and associated delays in moving theoil to the refinery. A swap can also involve an exchange of crude oil for products suchas gas or heating oil. A swap transaction can consist of various payments made or received such as periodicpayments, up front payments, or termination payments. A periodic payment isgenerally based upon an interest rate or index factor multiplied by a notional principalamount. An up front payment can be an agreed upon lump sum payment such as a 4-4  premium paid to enter into a swap contract. A termination payment is a paymentmade or received to terminate or assign the rights of a swap contract. Forward Market The forward market is where oil is bought and sold between two parties with thedelivery of the commodity to be consummated at a future date. This type oftransaction does not take place through a commodity exchange. Forward contractsare the vehicle used in this market. Forward Contracts Commodity futures and forward contracts were originally developed as a tool to hedgebusiness inventory. A forward contract is used to acquire an agreed upon item at aspecified price with delivery at a future date. A forward contract is defined as thefollowing: Any contract that is entered into between two parties for delivery of specifiedproperty at a future date and that is not traded on an exchange or board oftrade. A crude oil producer incurs fixed costs to operate and maintain wells and relatedequipment such as labor to operate the wells and related equipment, repairs andmaintenance, materials, supplies, and property taxes. The producer has a risk that themarket price of crude oil might fall by the time it is ready to deliver. In order toreduce this risk, the producer can enter into a forward contract by which the crude oilis sold at a high price ensuring a profit in exchange for delivery of the oil at a futuredate. A manufacturer of oil such as a refiner might need a supply of crude oil andwant to purchase the oil at a low price. To ensure an adequate supply, the refiner mayenter into a contract to buy crude oil at a low price with future delivery. Oil producersand refiners are acting as hedgers when utilizing forward contracts to reduce theirinventory risks. Forward contracts currently are entered into in a wide variety of financial products inthe marketplace, such as foreign currency contracts, government securities, debtinstruments, and even stock. 4-5  Futures Market There are two markets in the energy futures: New York Mercantile Exchange(NYMEX) and International Petroleum Exchange (IPE). Both exchanges tradefutures contracts and options on futures contracts. Energy futures and options on futures are closely related, but are not interchangeable. Each has its own advantages and disadvantages and can be used in various ways forrisk management or investment purposes. The level of risk in futures trading differsfrom options trading. The risk in purchasing an options contract is limited to thepremium paid while the risk of trading futures is much greater. Margin deposits arerequired on futures transactions. While no deposit is imposed upon purchasing anoptions contract, margin is required upon writing an options contract. Below is a chart that reflects the types of futures contracts and sizes that are handledby NYMEX and IPE. Exchange Traded Energy FuturesFutures ContractContract SizeMinimum FluctuationNYMEX: Crude Oil1,000 Barrels(42,000 Gallons) 1 Cent/Barrel = $10 No. 2 Heating Oil42,000 Gallons1/100 cents/gal = $4.20 Unleaded Gasoline42,000 Gallons1/100 cents/gal = $4.20 Propane42,000 Gallons1/100 cents/gal = $4.20IPE: Gas Oil100 Metric TonsU.S. 25 cents/ton = $25 Heavy Fuel Oil100 Metric TonsU.S. 25 cents/ton = $25 Premium Leaded Gasoline100 Metric TonsU.S. 25 cents/ton = $25 Crude Oil1,000 BarrelsU.S. 1 cent/barrel = $10 4-6  Futures Contracts Energy futures began trading on NYMEX in 1978 and the IPE was established inApril of 1981. A commodity exchange does not buy or sell futures contracts, it onlyprovides a facility for its members to buy and sell contracts for their own account andfor the accounts of public customers. Contracts are traded in an exchange by membersthrough an auction system of open outcries of competitive bid (buy) and ask (sell) prices. Domestic futures exchanges are regulated by the CFTC. A futures contract is a forward contract that is traded on an exchange or board oftrade. It is defined as a bilateral contract to buy or sell a fixed quantity of a specifiedcommodity at a stated price with delivery to take place on a specified date in the futureand that is traded on an exchange. A buyer of a futures contract agrees to accept delivery of the underlying commoditywhile a seller agrees to make delivery. The majority of futures contracts are closedthrough an offsetting buy or sell position of an identical futures contract, a contract forthe same commodity with the same delivery date. Therefore, a delivery of thecommodity does not take place. The price of a futures contract reflects the market'sconsensus regarding the expected price of a commodity in the future relative to supplyand demand for that commodity. To open and maintain a commodity account with a brokerage firm, margin must bedeposited in the account. Margin is a performance bond which acts as collateral forthe purpose of insuring a broker that the account will have sufficient funds to coverpotential losses. Brokerage firms compute each clients total account equity on a dailybasis by computing the unrealized gains and losses on open positions (termed mark tomarket) plus the realized gains and losses and cash deposited. If the account has adebit balance, a margin call for more money will be made. Futures Transaction. Straddles are a common investment strategy used by manypeople to take advantage of price differences between the buy and sell positions. Thestraddle is also known as balanced positions. It is where one is buying and sellingsimultaneously on or near the same trade date of either the same commodity or relatedcommodity. The following are examples of straddles. A crude oil refiner entered into the following crude oil futures contracts on theNYMEX: 4-7  Trade DatePositionContractsDeliveryDateTotal Price08-01-89Sell[40]July$2,000.0008-01-89Buy40March(1,951,000) 08-04-89Buy40May(1,851,000) 08-04-89Sell[40]March2,825,00002-18-90Sell[40]May2,025,00002-18-90Buy40July(2,051,000) There is an equilibrium effect with a straddle. For example, when the price of acommodity increases, there is a potential gain in the buy position and a potentialoffsetting loss in the sell position. Options Contracts Options trading in the energy futures started in 1986 with trading done by NYMEX. It was introduced to provide different hedging or investment alternatives and to meetthe needs of the market participants. It appears that options add increased flexibilityto hedging and other trading programs. Today options on energy futures contracts aretraded on the NYMEX and IPE. An option is a unilateral contract conveying the right to buy and sell a specific item ata specified price within a specified period of time. The underlying property in anoption contract can be any type of property such as real estate, stock, or futures. Below is a chart that reflects the type of options contract and size that are handled byNYMEX and IPE. Exchange Traded Energy OptionsUnderlyingFuturesContractContract SizeStrike PriceIncrementsMinimum FluctuationNYMEX: Crude Oil1,000 Barrels(42,000 Gallons) $1/Barrel1 Cent/Barrel = $10 Heating Oil42,000 Gallons2 Cents/Gallon1/100 Cents/Gallon = $4.20IPE: Gas Oil100 Metric Tons$5/Ton5 Cents/Ton = $5 4-8  Basic Types of Options There are two types of options that are traded: a call and a put. A call option is acontract that entitles the purchaser to the right to buy the underlying futures contractat a specific price within a specified period of time. A put option is the opposite of acall; it entitles the purchaser to the right to sell the underlying futures contract at aspecific price within a specified period of time. A call and a put are separate, distinctvehicles that are used for different strategies and purposes. The exercise price, also known as the strike price, is the price at which an optionholder may buy or sell the futures contract. The last day on which an option can be exercised is termed the expiration date. If anoption has not been exercised prior to the specified expiration date, it expires andceases to exist. That is, the option buyer no longer has any rights; therefore, theoption no longer has any value. The purchaser of an option pays a premium for the right to acquire the option. Anoption premium does not constitute a down payment. The premium is simply a fullynon-refundable payment for the rights conveyed by the option. It is the price of theoption. Parties in an Option There are always two parties in an options contract. They are the option purchaserand the option writer. The option purchaser (buyer) is the individual who purchases the option. The optionpurchaser is also referred to as the holder. The purchaser pays a premium to obtainthe right to buy or sell the specified property at a certain price. Only the optionpurchaser has the right to exercise an option. The purchaser of a call option pays apremium for the right to buy the underlying property. The purchaser of a put optionpays a premium for the right to sell the underlying property. The second party to an options contract is the option writer also referred to as theseller or the grantor of the option. The option writer receives the premium and isobligated to sell the underlying property at the specified price if the option buyerchooses to exercise the call. The writer of a put option receives a premium and isobligated to buy the underlying property at a specified price if the option buyerchooses to exercise the option. For every call option traded, there is a call purchaserand a call writer (seller), and for every put option traded there is a put purchaser and aput writer (seller). Opening and Closing Transactions The initial purchase or sale transaction that results in an individual becoming apurchaser or writer of an option is termed the opening transaction. A closingtransaction cancels out an investor's previous position as the purchaser or the writer of 4-9  an option. Examples of closing transactions are where the purchaser of an optionenters into an offsetting sale of an identical option, or the writer of an option makes anoffsetting purchase of an identical option. Termination of an Options Contract Option Purchaser. There are three ways in which an option purchaser can terminatean options position. They are as follows: 1.Do nothing and allow the call or put option to expire. The purchaser incurs a lossequal to the option premium paid. 2.Exercise the option. Upon exercise, a call purchaser takes delivery of the underlying futures contractand pays the exercise price. A call writer would be assigned the obligation to sell; the assignment would be conducted through an options exchange. Upon exercise, a put purchaser is obligated to make delivery of the underlyingfutures contract and receives the exercise price. 3.Enter into a closing transaction, also termed an offsetting position. The purchaser of a call closes the position by selling the same option series thatcontains the same expiration date and exercise price. The purchaser of a put closes the position by buying the same option series. Option Writer. There are three ways that an option writer's obligation can terminate. They are as follows: 1.A put or call option may lapse without being exercised by purchaser. The writerrecognizes income in the amount of premium received. 2.A put or call option may be exercised by the purchaser. The writer of a call that is exercised must deliver the underlying futures contract inexchange for the exercise price. The writer of a put that is exercised must pay the exercise price and receives theunderlying futures contract. 3.An option writer may enter into a closing transaction (offsetting position). 4-10  Market Participants in Forward and Futures Contracts As stated previously, the oil marketplace consists of the cash market, the forwardmarket, and the futures market. According to an article in the Oil and Gas Investor, June 1988, participants in the marketplace include refiners, producers, marketers, consumers, and speculators. Amoco, Arco, Chevron, Mobil, Murphy Oil, RoyalDutch/Shell, Mesa Petroleum Co., Marathon, and Diamond Shamrock R&M wereacknowledged as trading futures contracts on the NYMEX. Investment banking firmshave also traded on the NYMEX such as J. Aron & Co., Inc., Drexel Trading ofDrexel Burnham Lambert, Morgan Stanley, and Bear Stearns. The investment bankersare traders and have no intention of actually owning any oil. Another participant is thefloor trader that is a member of the NYMEX trading for his or her own account. Thearticle stated, These traders do not care whether the market is pork bellies or frozenorange juice. It's all the same to them if the price in whatever they're trading is goingup or down. Speculators Hedgers, such as producers and manufacturers, are not necessarily going to buy andsell futures or forward contracts at the same time. Someone who trades contracts andis not a hedger is known as a speculator. A speculator trades for his or her ownaccount for a profit. The speculator provides a liquid marketplace for the hedger. Most exchange members are not hedgers, but merely speculators seeking a profit fromtrading for their own account. Speculators can include investors and traders. Hedgers The definition of the word hedge is the reduction of risk. The term hedge or hedger iscommonly used to refer to financial transactions because such transactions are enteredinto to reduce one's risk. A tax hedge is a financial transaction in futures or forwardcontracts entered into by a dealer to reduce the risk of holding inventory. For taxpurposes, a hedge transaction must meet certain judicial and legislative criteria whichwas established in Arkansas Best v. Commissioner, 485 U.S. 212 (1988) and IRCsection 1256(e) to receive ordinary loss treatment. In addition to the court case, examiners should consult Temp. Treas. Reg. section 1.1221-2T and Treas. Reg. section 1.1221-2(c)(2), (c)(4), and (c)(5)(ii) for further guidance as to hedgingtransactions. The temporary regulation section set out above is applicable to hedgingtransactions entered into on or after January 1, 1994, or entered into on or before thatdate and remain into existence on March 31, 1994. If an examiner has a hedging issue, a financial products specialist should becontacted for assistance. After contacting the specialist, it could be determined that areferral may be in order. Investor One who trades for potential profit for its own account is considered to be an investor. An investor can trade energy forward or futures contracts for various reasons such as 4-11  long term appreciation or short term profits. An investor can be someone who has nodirect interest in oil. However, it can also be an entity involved in the oil industry thatenters into contracts for profit speculation separate and apart from hedging its businessinventory. The financial transactions of an investor generally give rise to capital gainsor losses. Trader A trader is someone who trades futures or forward contracts on a regular basis for itsown account. One must meet certain judicial requirements established in King v. Commissioner, 89 T.C. 1214 (1988), to be considered a trader for tax purposes. Atrader is in a trade or business of trading for his or her own account. The financialtransactions of a trader give rise to ordinary gain or loss treatment and the relatedexpenses are deductible under IRC section 162 as trade or business expenses. Amember of the NYMEX who trades futures for his or her own account as a floortrader is a trader for tax purposes. COMMODITY NOTIONAL CONTRACTS Commodity Notional Swap In a commodity notional swap, one party agrees to pay the spot price of thecommodity at specified intervals for a notional amount of the commodity. In return itreceives a fixed price based on the same notional amount of the commodity for aspecified period of time. The notional amount of the commodity on which thepayments are based is not exchanged between the parties. Most commodity notionalswaps are based on oil and other energy related products. Use of Commodity Notional Swap to Hedge Risk For example, an oil producer seeking a stable price for its oil sales can use acommodity notional swap to lock in prices by paying the spot (market) price under theswap in return for a fixed payment (for example, $20 for each notional barrel of oil). The spot price the producer will receive when it sells the physical commodity in themarketplace will offset the payment of the spot price under the swap contract. The net effect of the swap and the sale of the physical commodity together is that theproducer receives a fixed payment of $20 per barrel of oil sold. Though the oil producer has fixed its income stream, it will not benefit if oil pricesincrease to $25. The producer will receive more from the sale of oil, but it owespayments to its swap counterparty based on the higher spot price. Thus, swaps notonly hedge the downside, they also give up the upside. 4-12  GLOSSARY There are many terms that are synonymous with the oil and gas industry. Below are termsthat are encountered when examining an oil and gas entity or activity. Even though some ofthe terms are not discussed or used in this audit techniques guide, this glossary will be helpfulto you as they will be encountered sometime during an examination. ABANDON: To discontinue attempts to produce oil or gas from a well or lease and to plug the reservoir in accordance with regulatory requirements and recover equipment. ACIDIZE: Increase the flow of oil from a well by introducing acid into a limestone formationto open passages through which oil can flow into the well bore. ACQUISITION WELL: A well drilled in exchange for a mineral interest in a property. It isalso referred to as an obligation well. ACRE-FOOT: A reservoir analysis measure of volume. One acre foot represents the volume which would cover one acre to a depth of one foot. ADVANCED ROYALTY: An advance payment made by the owner of an operating interestto the royalty owner for a specific number of units of minerals regardless of whetheroil or gas was extracted within the year. The payment is recoverable out of futureproduction. AFE: Authorization for expenditures. It is a form used during the planning process for a wellabout to be drilled. It can also be used for other projects. The form includes anestimate of costs to be incurred in the intangible drilling costs (IDC) category and inthe tangible equipment category. Costs are shown in total with accompanyingbreakdowns. The form represents a budget for the project against which actualexpenditures are compared. AIR DRILLING: The use of compressed air as a substitute for drilling mud in rotary drilling. AIR/GAS LIFT: Method of raising oil from the formation by injecting air or gas directly intothe fluid in the casing. ALLOWABLE: The regulated amount of oil or gas that a well or lease can produce during agiven time period. ANTICLINES: Underground mountain-shaped strata covered with caprock or an impervious layer. API: Abbreviation for American Petroleum Institute, established in 1920. G-1  API GRAVITY: Liquid petroleum product measure of gravity of the product. Derived froma formula using specific gravity. APPORTIONMENT ACCOUNTS: Accounts used to accumulate expenses during a period, with the accounts being credited for amounts charged to activities on somepredetermined basis. ASSOCIATED GAS: Natural gas, occurring in the form of a gas cap, overlying an oil zone. BAFFLES: A device which changes the direction of flow of fluids. BARREL (BBL): A standard measure of volume for crude oil and liquid petroleum products. One barrel equals 42 U.S. gallons. BATTERY: Group of lease storage tanks. BEAM: The horizontal portion of an I beam pumping unit. BEAM WELL: A well from which oil is lifted by using a pumping unit and sucker rods and pump. BLOWOUT: Strong flow of oil or gas, uncontrolled, from a reservoir to the surface and intothe atmosphere. BOILERHOUSE: A slang term. Fake a report without having performed any work. BONUS: The consideration received by the lessor or sublessor on execution of the oil or gas lease. BOTTOM HOLE CONTRIBUTIONS: Money or property given to an operator for their use in drilling a well on property in which the payor has no property interest. Thecontribution is payable when the well reaches a predetermined depth, regardless ofwhether the well is productive or nonproductive. Usually, the payor receivesgeological data from the well. BOTTOM HOLE PRESSURE: The pressure at the bottom of a well in the producing formation. BRITISH THERMAL UNIT (BTU): A measure of the amount of heat required to raise thetemperature of one pound of water one degree Fahrenheit. BS OR BS&W: An abbreviation for basic sediment, or basic sediment and water. BS&W is produced along with oil. CARRIED INTEREST: A sharing arrangement in which one party agrees to pay the cost incurred on behalf of another which is the carried party. After production begins, the carried party receives no income until the carrying party has recouped all of theircosts incurred on behalf of the carried party. G-2  CARRIED PARTY: The party for whom funds are advanced in a carried interest arrangement. CARRYING PARTY: The party advancing funds in a carrying interest arrangement. CARVED-OUT INTEREST: An interest that occurs when the owner of a working interest assigns it to another as an overriding royalty, net profits interest, or productionpayment. CARVED-OUT OIL OR GAS PAYMENT: A payment in oil or gas assigned by the ownerof a working interest or fee interest. The payment is expressed in dollars, in barrels, in MCF, or as a period of time, to be paid out of a fractional part of the fee interestor working interest. The payment will run for a period shorter than the life of theinterest from which it was carved. CASINGHEAD GAS: Gas produced along with crude oil from oil wells. CASING PRESSURE: Gas pressure in a well that is built upbetween the casing and tubing or casing and drill pipe. CATHEAD: A spool shaped device attached to a winch around which rope is wound for hoisting and pulling. CATLINE: A hoisting or pulling line powered by a cathead; lifts equipment around the rig. CAT WALK: The narrow walkway on a drilling rig or on top of a tank battery. CELLAR: An excavation under the rig floor to provide space for working equipment during drilling. CENTRIFUGE: Machine in which samples of oil are placed and whirled at high speed to break out sediment. CHECKERBOARD ACREAGE: Mineral interests situated in a checkerboard pattern. Generally, this is done to spread the risk or to make sure the producer will havesome ownership if production is found. CHRISTMAS TREE: A term applied to the valves and fittings assembled at the top of a well to control the flow of oil. CLEAN OUT COSTS: Costs incurred to clean out a well to maintain its productive capacityor to restore it to original capacity. For example, the cost of removing sand andtubing or opening the pores in the producing formations. CLEARING ACCOUNTS: Accounts used to accumulate expenses during a period, with the balance allocated to other accounts on some predetermined basis at the end ofthe period. (See also APPORTIONMENT ACCOUNTS.) G-3  COMPLETION: Refers to the work performed and the installation of permanent equipment for the production of oil or gas from a recently drilled well. CONDENSATE: A light hydrocarbon liquid which is in a gaseous state in the reservoir but which becomes liquid at the surface. CONNATE WATER: Water originally in the producing formation. CONTINUING INTEREST: Any interest in mineral property that lasts for the entire periodof the lease contract with which it is associated. CONVEYANCE: The assignment or transfer of mineral rights to another person. COST CEILING: The limit placed on the carrying value of mineral assets in the cost center. COST CENTER: The geological, geographical, or legal unit with which costs and revenues are identified and accumulated. Examples are the lease, the field country, etc. CROSS SECTION MAPPING: Maps of cross-section of underground formation. CRUDE OIL: Liquid petroleum after being produced but before being refined. DAILY DRILLING REPORT: Twenty-four hourly report indicatingall important events which occurred on a drilling rig. DAMAGE PAYMENTS: Payments made to the landowner by the oil or gas operator for damages to the surface, to the growing crops, to streams, or to other assets of thelandowner. DAY RATE CONTRACT: An agreement between a drilling rig contractor and an operator wherein an agreed amount of money per day will be paid to the drilling contractoruntil a well is drilled to an agreed upon depth. DEFERRED BONUS: A lease bonus payable in installments over a period of years. The deferred bonus is distinguishable from delay rentals because the deferred bonuspayments are due even if the lease is dropped, whereas delay rentals are discontinuedwith the dropping of the lease. It is also known as an Installment Bonus. DELAY RENTALS: These are amounts paid to the lessor for the privilege of deferring the commencement of a well on the lease. Oil and gas lease agreements generallyprovide a deadline for the lessee to begin drilling of the lease. If the drilling has notbegun within this period of time, either the lease agreement will expire or the lesseemust pay a stated sum of money to retain the lease an additional year withoutdeveloping the property. DELINEATION WELL: A well to define, or delineate, the boundaries of the reservoir. G-4  DEPLETION: Amortization of capitalized costs of a mineral property. The deduction is based upon minerals produced. For federal income tax purposes, depletion may bebased on the amount of gross income from the property. DETAILED SURVEY: An intensive geological and geophysical exploration of an area of interest. DEVELOPMENT WELL: A well drilled within the proved area of an oil or gas reservoir tothe depth of a horizon known to be productive. DEVIATED WELL: A well drilled at an angle from the vertical. DIRECTIONAL DRILLING: Intentionally drilling a well at an angle from the vertical. DISPOSAL WELL: A well through which salt water is pumped to subsurface reservoirs. DISSOLVED GAS: Natural gas mixed with crude oil in a producing formation. DIVISION ORDER: A document that describes the economic interest owners of a property and the types of interest owned. It is used by the purchaser as the basis for payingeach economic interest owner their share of revenue. DOGHOUSE: A small house on the rig floor used for keeping records, storage, etc. DOUBLE: Two lengths or joints of drill or other pipe joined together. DRY GAS: Natural gas composed of vapors without liquids and which tends not to liquefy. DRY HOLE: An exploratory or development well that does not produce oil or gas in commercial quantities. DRY HOLE CONTRIBUTIONS: Money or property paid by adjoining property owners toanother operator drilling a well on property in which the payors have no propertyinterest. Such contributions are payable only in the event the well reaches an agreeddepth and is found to be dry. ECONOMIC INTEREST: An economic interest is possessed in every case in which the taxpayer has acquired by investment any interest in mineral in place and secures, byany form of legal relationship, income derived from the extraction of the mineral towhich one must look for a return on the capital. ENHANCED RECOVERY: Any methods used to extract oil from reservoirs in excess of that which may be produced through primary recovery. EXPLOITATION ENGINEERING: Engineering related to subsurface geology, the recovery of fluids from reservoirs, and the drilling and development of oil reserves. G-5  EXPLORATION COSTS: Costs incurred in identifying areas that may warrant examination, and in examining specific areas, including drilling exploratory wells andexploratory stratigraphic type test wells. EXPLORATION RIGHTS: Permission granted by landowners allowing others to enter upon their property for the purposes of conducting geological and geophysicalsurveys. EXPLORATORY WELL: All wells drilled to search for or produce oil or gas except the cost of development wells and development type stratigraphic test wells drilled togain access to proved reserves. FARM-IN: An agreement in which a person agrees to drill one or more wells in exchange forreceiving a working interest from the person holding the lease. FARMOUT: An agreement in which the person holding a lease assigns a working interest in the property to another in exchange for drilling one or more wells. FAULTS: The breaks in strata resulting from significant moving or shifting of the earth's surface. FEE INTEREST: Ownership of both mineral and surface rights on a tract of land. Also called fee simple. FIELD:An area consisting of a reservoir or multiple reservoirs related to the same geological structural feature. Reservoirs in overlapping or adjacent fields may betreated as a single operational field. FIELD EXPLORATORY WELL: A well drilled in an area where there was previous production, but outside the limits of the known reserves. It is also known as adelineation well. FIELD FACILITY: Oil and gas production equipment serving more than one lease. For example, separator, extraction unit, etc. FIELD PROCESSING: Treating oil or gas before it is delivered to a gas plant or refinery. FIRE WALL: An earthen dike built around an oil tank to contain the petroleum if the tank ruptures. FLOW CHART: A record of the production of gas measured by a meter. FLOWING WELL: A well which lifts oil and gas to the surface with natural reservoir pressure. FLOW LINES: The surface pipes through which oil moves from the well to the lease tank. FLOW TANK: The tank into which oil is stored after being produced. G-6  FLOW TREATER: A piece of equipment which separates oil and gas, heats oil, and treats oil and water. FLUID INJECTION: Inducing gas or liquid into a reservoir to move oil toward the well bore. FLUSH PRODUCTION: The large flow of production initially made by a well after being drilled. FOOTAGE DRILLING CONTRACT: A well drilling contract which provides for paymentat a specified price per foot for drilling to a certain depth. FORMATION PRESSURE: Bottom hole pressure of a shut-in well. FRACTURING: A procedure to stimulate production by forcing under high pressure a mixture of oil and sand into the formation. FREE WELL AGREEMENT: A form of sharing arrangement in which one party drills one or more wells completely free of cost to a second party in return for one type ofeconomic interest in property. FULL COSTING: A concept under which all costs incurred in searching for, acquiring, and developing oil and gas reserves are capitalized. GEOLOGICAL and GEOPHYSICAL (G & G): Surveys of a topographical, geological, and geophysical nature along with other costs incurred to obtain the rights to makethese surveys, and salaries and other expenses of the personnel required to carry outthe surveys are often referred to as G & G costs. GAS OIL RATIO: A measure of the volume of gas produced along with oil from the same well. GAS INJECTION: Gas is injected into a formation to maintain pressure or for secondary recovery. Reproduced injected gas cannot usually be distinguished from the originalformation gas. GAS LIFT GAS: Gas injected into the well bore to lift the oil to surface. Gas lift gas, unlikeinjected gas, returns immediately to the mouth of the well without entering thereservoir. Normally, the sales price for recovered gas lift gas is lower. GAS PAYMENT: A production payment payable out of gas produced. GAS PLANT PRODUCTS: Natural gas liquids removed from natural gas in gas processing plants or in field facilities. GAS WELL: A well producing natural gas. G-7  GATHERING LINES: A small pipeline which moves the oil from several wells into a singletank battery or major pipeline. GAUGE TICKET: A form on which the measurement of oil in lease tanks is recorded. GRAVITY: A standard American Petroleum Industry (API) scale which is related to specificgravity of a petroleum fluid based on a technical formula. On this scale the greaterthe density of the petroleum, the lower the API degree. The higher the API gravity, the greater the value of the oil. GRAVITY METER: An instrument measuring the variations in the gravitational pull. HORIZON: An underground geological formation which is the portion of the larger formation which has sufficient porosity and permeability to constitute a reservoir. HORIZONTAL ASSIGNMENT: An assignment of an interest in the minerals above or below or between specified depths, or in a given stratum or horizon. HYDROCARBON: An organic compound of hydrogen and carbon. INDEPENDENT PRODUCER: It is defined in IRC section 613A(d) as a producer who does not have more than $5 million in retail sales of oil or gas in a year and whodoes not refine more than 50,000 barrels of crude on any day during the year. Anexemption from the denial of percentage depletion is provided in IRC section613A(a) for independent producers if production is within the limits of the averagedaily production of oil and gas set in IRC section 613A(c). INTANGIBLE DRILLING COSTS (IDC): Any cost which in itself has no salvage value and is necessary for and incident to the drilling of wells and getting them ready forproduction. IDC can also occur when deepening or plugging back a previouslydrilled oil or gas well, or an abandoned well, to a different formation. IGNEOUS ROCK: Rock that is formed directly from the molten state. INJECTION OR INPUT WELLS: A well used to inject gas, water, or liquid petroleum gas(LPG) under high pressure into a producing formation to maintain sufficient pressureto produce the recoverable reserves. IN SITU COMBUSTION: The setting afire of some oil in the reservoir to create a burning front of gases which will drive oil ahead of it to the well bore. ISOPACH MAPS: Maps showing variations in the thickness of a particular sedimentary bed and also can show the interval or spacing between one bed and another. JOINT: A single length of drill pipe, casing, etc. usually from 20 to 30 feet in length. G-8  JOINT INTEREST AUDIT: An audit performed by or on behalf of the non-operator working interest owners to determine if the operator is conforming to the provisionsof the operating agreement and accepted accounting procedures. JOINT INTEREST or JOINT VENTURE: An association of two or more persons or companies to drill, develop, and operate jointly properties. Each owner has anundivided interest in the properties. KILL A WELL: To bring high well pressure under control by the use of mud or water so that the well may be completed, etc. LACT UNIT (LEASE AUTOMATIC CUSTODY TRANSFER UNIT): A unit which is used to account for purchases of oil. The LACT unit automatically transfers the oil, records the information, and prepares the run ticket. LANDMAN: A person experienced in mineral leasing activities. LEASE AGREEMENT: An agreement between two or more parties by which a lessee is given the right to enter a property, survey and locate a well site, perform drillingoperations, and remove any minerals found. LEASE BONUS: The consideration paid by the lessee to the lessor for executing the lease. LEASE AND WELL EQUIPMENT: Capital investment in items of equipment having a potential salvage value and used in a well or on a lease. Such items include the costof casing, tubing, well head assemblies, pumping units, lease tanks, treaters, andseparators. LESSEE: The person who leases the mineral rights from the owner in order to drill and operate wells. LESSOR: The person who owns the mineral rights and has executed a lease. LIFTING COST: All customary expenses incurred in connectionwith the production and marketing of oil and gas. LOCATION: The site for a well to be drilled or at which a well has been drilled. LOGGING: The taking and recording of physical measurements about formations being drilled. MARGINAL WELL: A well whose production is so limited that it is no longer profitable tooperate. MCF: Thousands of cubic feet of natural gas. METAMORPHIC ROCKS: Rocks developed as a result of being subjected to heat and pressure. G-9  MINIMUM ROYALTY: An obligation of a lessee to periodically pay the lessor a fixed sumof money after production occurs, regardless of the amount of production. Suchminimum royalty may or may not be chargeable against the royalty owner's share offuture production. MISCIBLE FLUID: A secondary recovery process which involves the injection of a mixtureof hydrocarbons which displaces fluid. MMCF: Millions of cubic feet of natural gas. MOBILE DRILLING RIG: A drilling rig used offshore. It floats from one drill site to another. Drill ships, jack-ups, and semi-submersibles are mobile rigs. MUD: Drilling fluid circulated through the drill pipe and backto the surface during rotary drilling and workovers. MULTIPLE COMPLETION WELL: A well producing oil and/or gas from more than one reservoir. NATURAL GAS: Hydrocarbons that exist in the gaseous phase under certain atmospheric and temperature conditions. NATURAL GAS LIQUIDS: Hydrocarbons which can be extracted from natural gas. NET PROFITS INTEREST: This is an interest carved out of the working interest. It is a nonoperating interest that shares in the net profits, if any, but has no liability forcapital investments or losses. NEW FIELD WILDCAT: A well drilled in an area where previously there had been no production of oil or gas. NONASSOCIATED GAS: Natural gas not in contact with reservoirsthat contain significant quantities of crude oil. NONCONTINUING INTEREST: An interest in a mineral property whose life is limited in terms of dollars, units of production, or time. NONOPERATING INTEREST: An interest in an oil or gas property that bears no costs of development or operation, such as the landowner's royalty interest. NONOPERATING WORKING INTEREST: A working interest owner that does not participate in the day-to-day operations of developing and operating a mineralinterest. OFFSET: Drilling a well adjacent to another. OFFSET WELL: Well drilled on one tract of land to prevent drainage of oil or gas to a nearby tract on which a well has been drilled. G-10  OIL PAYMENT: A production payment payable out of oil produced. OIL POOL: An underground reservoir containing oil in the sedimentary rocks. OIL SAND: Any porous reservoir containing oil. OIL SEEP: Areas where tiny amounts of petroleum have migratedto the surface. OIL WELL: A well that is being pumped because it will notflow. OPERATOR: One who holds the working or operating rights and is obligated for the costs of development and production, either as a fee owner or as an assignee. OPERATING WORKING INTEREST: A working interest owner who participates in the day-to-day operations of developing and operating the mineral interest. OPERATING INTEREST: See Working Interest. OUTPOST WELL: A well drilled in an attempt to make a long extension of a producing pool; a well located outside the established reservoir boundaries. OVERRIDING ROYALTY INTEREST: This is an interest carved out of the working interest which does not require the owner to bear a share of the developing oroperating cost. It exists only for a stipulated time, but never longer than the life ofthe working interest. It is a nonoperating interest. PERCENTAGE DEPLETION: A deduction for federal income tax purposes based on the gross income from mineral properties. Percentage depletion is in lieu of costdepletion. It is also known as Statutory Depletion. PERFORATE: To penetrate the well casing with holes made with a perforating gun. PERMEABILITY: The porosity of a given formation providing oil with the ability to flow. PIG: A scraping instrument for cleaning a pipeline. PLUG BACK: To seal off a lower formation in a well bore inorder to produce from a higher formation. POOL: An underground reservoir having a common accumulation ofoil or gas. POROSITY: The condition of a formation which permits oil to flow. POSTED PRICE: The price published and circulated betweenbuyers and sellers in a particular field. G-11  PRESSURE MAINTENANCE: Injection of gas, water, etc. to repressure an oil field. PRESSURE REGULATOR: An instrument for maintaining pressure in a pipeline; downstream from the valve. PRICE BULLETIN: A posting of the price per barrel the purchaser will pay for each grade of crude oil in a field. PRIMARY RECOVERY: Oil which is forced into the well bore by natural reservoir pressure. PRIMARY TERM: The maximum period of time allowed by a lease for the lessee to commence drilling a well. Drilling cannot be deferred beyond the primary term, evenby the payment of delay rentals. PRODUCE: For purposes of IRC section 263A, it includes construct, build, install, develop, manufacture, improve, create, raise or grow. PRODUCER: A generic term used to refer to all economic interest holders in a property. PRODUCTION PAYMENT: A right to minerals in place which entitles its owner to a specific fraction of production for a limited period of time, or until a specific sum ofmoney or a specific number of units of mineral has been received. PRODUCTION TAXES: Taxes levied by state governments on mineral production based upon the value and/or quantity of production. They are also known as severancetaxes. PRODUCTIVITY TEST: A test of the maximum or other rates at which a well can produce. PROJECT AREA: A large territory that the taxpayer determines can be explored advantageously in a single integrated operation. PROPERTY: Each separate interest owned by a taxpayer in each mineral deposit in each separate tract or parcel of land. Certain interests may be combined to form aproperty. See IRC section 614 for the codified definition of property. PRORATION: A system of allocating production from a well permitted to be produced during a period of time. PROSPECT: A lease or a group of leases on which an owner proposes to drill one or more wells. PROVED DEVELOPED RESERVES: Reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. G-12  PROVED RESERVES: Quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be recoverable in the future from known oil andgas reserves under existing economic and operating conditions. PROVED UNDEVELOPED RESERVES: Reserves which are expected to be recovered from new wells on undrilled proved acreage, or from existing wells where arelatively major expenditure is required for completion. PROVEN PROPERTIES: A property whose principal value has been demonstrated by exploration, discovery, or development. PUT ON A PUMP: To install a pump jack or pumping unit, sucker rods, and bottom hole sucker rod jump. PUT ON A WELL: To begin a well flowing or pumping. RABBIT: Line cleaning instrument. A small plug which is run through a line. RECONNAISSANCE SURVEY: A survey of a project area utilizing various geological andgeophysical techniques to identify specific geological features with sufficient mineralproducing potential to merit further exploration. RETAINED INTEREST: The interest created when the owner sells the working interest and retains an overriding royalty, a net profits interest, or a production payment. An owner can retain the working interest and sell the others. REMIT SLIP: Check stub from payee of oil and or gas. It will usually indicate barrels or MCF, gross revenue or net revenue, and the amount actually paid. ROYALTY INTEREST: An ownership interest that entitles its owner to share in the production from the mineral deposit, free of development and operating costs, andextends undiminished over the productive life of the property. It is a nonoperatinginterest. RUN TICKET: A document, prepared by the purchaser's gauger and witnessed by the lease pumper, which records the quantity of oil removed, its gravity, temperature, andimpurities (Basic Sediment & Water or BS&W). SEISMOGRAPH: The instrument used to record the refraction of sound waves. SERVICE WELL: A well drilled for the purpose of supporting production; for example, a gas injection well or a water injection well. SPOT PRICE: A short-term price negotiated between the buyer and the seller. SPUD IN: To start drilling a well. G-13  STEP OUT WELL: A well drilled adjacent to a proved well in anattempt to determine the limits of the reservoir. STRATIGRAPHIC TEST WELL: A well drilled to obtain information about geologic conditions. This well is common for offshore drilling. Stratigraphic test wells areclassified as follows: (1) Exploratory-type stratigraphic test well (a stratigraphic testwell not drilled in a proved area) and (2) Development-type stratigraphic test well (astratigraphic test well drilled in a proved area). STRIP WELL: To pull both the rods and tubing from a wellsimultaneously. STRIPPER: A well nearing the end of its productive life; very little oil is being produced. STRUCTURAL MAPS: Maps that indicate subsurface features. SWAB: A device that fits tightly inside the tubing; when pulled through the tubing, it lifts fluid. SWEET OIL (OR GAS): Oil or gas without sour impurities. TAKE OR PAY CONTRACTS: An agreement in which a purchaser of gas agrees to take aminimum quantity of gas per year if one is not prevented from doing so bycircumstances beyond his or her control and if the gas is available for delivery. If thepurchaser does not take the minimum quantity, he or she is required to pay for thatminimum quantity at the contract price; normally, one may make up deficiencyamounts in future years if he or she purchases in excess of minimum amounts. TANGIBLE ASSETS: The cost of assets that in themselves have a salvage value. TANK STRAPPER: The individual who measures a tank and prepares a tank table. TANK TABLE: A table showing the volume of a tank at various levels based on 1/4(one-quarter) inch intervals. TERTIARY RECOVERY: The use of sophisticated techniques such as flooding the reservoir with chemicals to increase the production of oil or gas. THIEF: A device for extracting oil samples from a tank. TOP LEASE: A new lease obtained covering a property currently leased before theexpiration of the previous lease between the same parties. TRUNCATION TRAPS: Traps associated with noncomformities or discontinuities in the strata. TURNKEY WELL: A completed well, drilled and equipped by a contractor for a fixed price. G-14  UNITIZATION: An agreement under which two or more persons owning operating mineral properties agree to have the properties operated on a unified basis and further agreeto share in the production from all the properties on a stipulated percentage orfractional basis regardless of from which property the oil or gas is produced. Allowners of economic interests in the properties should be involved in the agreement. VISCOSITY: The ability of a fluid to flow as a result of its physical characteristics. WATERFLOODING: A method of secondary recovery in which water is injected into an oil reservoir for the purpose of pushing the oil out of the reservoir rock and into thebore of a producing well. WATER WELL: A well drilled to obtain a supply of water for drilling or operating use. WELL: A hole drilled in the ground to obtain geological information, find and produce oil orgas, or provide service to the operation of an oil or gas property. WET GAS: Gas that contains a large quantity of liquids. WORKING INTEREST: An interest which entitles the owner to share in the production and requires the owner to bear its share of the developing and operating cost. Thisis also known as an operating interest. The life of the working interest is tied to thelease. If the lease is terminated the working interest associated with the leaseterminates. WORKOVER COSTS: Expenses incurred in cleaning a well in an attempt to increase production. ZONE: A stratigraphic interval containing one or more reservoirs. G-15  This page intentionally left blank. TECHNICAL REFERENCES GENERAL COUNSEL MEMORANDUMS (GCM) AND COURT CASESCompensation for Services Other Than CashBlake v. Commissioner, 20 T.C. 721 (1953) Depletion on Lease BonusEngle v. Commissioner, 464 U.S. 206 (1984) Election to Expense IDCHawkeye Petroleum Corp. v. Commissioner, 18 T.C. 940 (1952) Excess Depletion Tax Preference ItemHill v. United States, 113 S.Ct. 941 (1993) IDC Funds Furnished by Related TaxpayerIsland Gas, Inc. v. Commissioner, 30 T.C. 787 (1958) Payments to Promoter-OperatorHedges v. Commissioner, 41 T.C. 695 (1964) Pool of Capital ConceptGCM 22730, 1941-1 C.B. 214Sale of Interest Subject to Capital Gains TaxGlenn v. Commissioner, 39 T.C. 427 (1962) Sand Fracturing is Production Expense, Not IDCProducers Chemical Co, v. Commissioner, 50 T.C. 940(1968) UnitizationsKillam v. Commissioner, 39 T.C. 680 (1963) Unsuccessful Lease AcquisitionsLarsen v. Commissioner, 66 T.C. 478 (1976) TR-1  REVENUE RULINGS REVENUE RULING NO. Assignments, Sales and ExchangesAcquisition and Option Fees...............................80-176, 1980-2 CB 97Assignment for Cash at Less Than Equipment Basis.......................................55-35, 1955-1 CB 286Fee Paid for Services Rendered.............................77-395, 1977-2 CB 8071-191, 1971-1 CB 7767-141, 1967-1 CB 153Fees Paid by Investors....................................83-137, 1983-2 CB 41Management Fee.......................................81-150, 1981-1 CB 119Natural Gas Sold After Removal From Premises - Less Than Representative Market Field Price (RMFP)...............................90-62, 1990-2 CB 158Property Sale With Zero Basis.............................75-451, 1975-2 CB 330Sale of Interest - Ordinary Income or Capital Gain.........................................73-428, 1973-2 CB 30366-226, 1966-2 CB 239Capital ExpendituresDepreciation on Well Equipment.............................78-13, 1978-1 CB 63Drilling Cost Deductible If Arm's Length..............................................73-211, 1973-1 CB 303Drilling Cost for Injection Wells - Primary Development...................................69-583, 1969-2 CB 41Drilling Cost Incurred Outside United States..........................................73-470, 1973-2 CB 8867-34, 1967-1 CB 72 TR-2  REVENUE RULING NO. Drilling Cost Paid for Production Payment Twice Cost...........................................75-446, 1975-2 CB 95Drilling Cost Paid In Turnkey Agreement.....................75-304, 1975-2 CB 94Drilling Cost With Right to Income During Payout.........................................69-332, 1969-1 CB 87Drilling Cost - Partnership Allocation......................68-139, 1968-1 CB 311Drilling Cost - Underground Storage 75-235, 1975-1 CB 97Drilling Cost - Taxpayer's Permanent Fractional Share.......................................71-206, 1971-1 CB 10570-336, 1970-1 CB 145Drilling Cost - 200 Percent Recoup Then Working Interest Terminates.............................71-207, 1971-1 CB 160Drilling to Acquire an Interest..............................70-657, 1970-2 CB 70Drilling to Acquire Site and Acreage.........................77-176, 1977-1 CB 77Easements - Underground Storage.........................75-234, 1975-1 CB 96Geological and Geophysical Costs...........................77-188, 1977-1 CB 76Installation of Production Facilities.........................70-414, 1970-2 CB 132Lease Acquisition - First Year Rental......................69-467, 1969-2 CB 14267-25, 1969-1 CB 15656-252, 1956-1 CB 210LPG Injected Into Oil Recovery Process73-469, 1973-2 CB 8570-354, 1970-2 CB 50Offshore Platforms, Onshore Fabrication Cost70-596, 1970-2 CB 68Partial Release of Lease68-78, 1968-1 CB 294Prepaid Drilling Cost71-579, 1971-2 CB 22571-252, 1971-1 CB 146 TR-3  REVENUE RULING NO. Royalty Interest Acquired for Services.........................83-46, 1983-1 CB 16Unrecoverable Gas - Underground Storage...................75-233, 1975-1 CB 95Definition of PropertyForeign Petroleum Deposits...............................68-551, 1968-2 CB 261Working Interest Not Personal Holding Company Income......................................77-127, 1977-1 CB 158Cost DepletionAllocation of Lump-Sum Payment - IDC and Leasehold Costs......................................73-211, 1973-1 CB 303Basis.................................................80-49, 1980-1 CB 127Basis for Calculating Surviving Spouse's Depletion Allowance on Community Property.............................................92-37, 1992-1 CB 195Installation Cost Classification.............................70-414, 1970-2 CB 132Recoverable Reserves - Adjustments to.....................67-157, 1967-1 CB 154Depletion, Gross Income, Net IncomeAd Valorem And Production Taxes.........................75-182, 1975-1 CB 176Ad Valorem Taxes Paid by the Lessee.......................72-165, 1972-1 CB 177Bonus Exclusion.........................................82-3, 1982-1 CB 36881-266, 1981-2 CB 13979-73, 1979-1 CB 218Carbon Dioxide..........................................82-17, 1982-1 CB 95Clifford Trust..........................................84-14, 1984-1 CB 147 TR-4  REVENUE RULING NO. Contract to Purchase Natural Gas..........................68-330, 1968-1 CB 291Cost Well.............................................80-342, 1980-2 CB 99Deduction of Loss......................................54-581, 1954-2 CB 112Depreciation of Lessor's Equipment.........................68-361, 1968-2 CB 264Foreign Tax Credit.....................................75-427, 1975-2 CB 296Gas Compression Cost....................................75-6, 1975-1 CB 178Gas Consumed in Manufacturing Process....................68-665, 1968-2 CB 280Geothermal Wells.......................................85-10, 1985-1 CB 181Market or Field Price77-33, 1977-1 CB 165Net Operating Loss......................................69-355, 1969-1 CB 65Net Profit Interest......................................73-541, 1973-2 CB 206Nonproducing Activities.................................56-433, 1956-2 CB 332Nonproductive Well IDC.................................77-136, 1977-1 CB 167Oil Removed But Not Currently Sold.......................76-533, 1976-2 CB 189Prepaid IDC..........................................71-579, 1971-2 CB 225Retailer Exclusion.......................................85-12, 1985-1 CB 181Sales Commissions......................................60-98, 1960-1 CB 252State and Federal Gasoline Tax Credit.......................66-266, 1966-2 CB 239Take Or Pay Payments...................................80-48, 1980-1 CB 99Tax or Book..........................................83-134, 1983-2 CB 103Taxes Paid by Lessee....................................72-165, 1972-1 CB 177Transfers of Proven Property..............................83-167, 1983-2 CB 104 TR-5  REVENUE RULING NO. Percentage DepletionNet Profits Interest......................................92-25, 1992-1 CB 196Retailer's Exclusion......................................92-72, 1992-2 CB 118Geological and Geophysical CostsTax Treatment of G&G...................................77-188, 1977-1 CB 7683-105, 1983-2 CB 51Intangible Drilling and Development Cost200 Percent Reversion Then Working Interest Terminates....................................75-4461, 1975-2 CB 95Allocation of Lump-Sum Payment - IDC and Leasehold...........................................73-211, 1973-1 CB 303Consolidated Returns....................................69-590, 1969-2 CB 170Depreciation - Underground Storage........................75-235, 1975-1 CB 97Downhole Equipment.....................................78-13, 1978-1 CB 63Drilling for Interest.....................................71-207, 1971-1 CB 16071-206, 1971-1 CB 10570-657, 1970-2 CB 70Drilling to Acquire Site Plus Acreage.........................77-176, 1977-1 CB 77Easement - Underground Storage..........................75-234, 1975-1 CB 96Expense Recognition....................................71-252, 1971-1 CB 146Farm-In of Two Properties...............................80-109, 1980-1 CB 129Foreign Properties.......................................87-134, 1987-2 CB 6973-470, 1973-2 CB 8867-34, 1967-1 CB 72 TR-6  REVENUE RULING NO. Full Recoupment.........................................69-332, 969-1 CB 87Geothermal Wells.........................................80-2, 1980-1 CB 61Injection Wells..........................................69-583, 1969-2 CB 41Limited Partnership......................................80-71, 1980-1 CB 106Nonproductive Wells....................................77-136, 1977-1 CB 167Offshore Exploration Wells................................88-10, 1988-1 CB 112Offshore Platforms.......................................89-56, 1968-1 CB 8370-596, 1970-2 CB 68Partnership Allocation...................................68-139, 1968-1 CB 311Partnership.............................................54-42, 1954-1 CB 64Permanent Interest Deductible as IDC.....................70-336, 1970-1 CB 145Prepaid IDC..........................................71-579, 1971-2 CB 22571-252, 1971-1 CB 146Reversion of Interest after Payout..........................71-207, 1971-1 CB 160Significance of Complete Payout Period.............................................71-206, 1971-1 CB 105Turnkey Agreement......................................75-304, 1975-2 CB 94Nonconventional Fuel CreditGas From Tight Formation.................................86-127, 1986-2 CB 4Oil Produced from Shale...................................92-100, 1992-2 CB 7Price Support Payments.................................... 85-77, 1985-1 CB 14 TR-7  REVENUE RULING NO. Nonrecourse LoanAcquisition Cost of Property................................78-29, 1978-1 CB 62Advanced Royalties......................................80-73, 1980-1 CB 128PartnershipsDistributive Share......................................68-139, 1968-1 CB 311Limited Partnership......................................80-71, 1980-1 CB 106Sharing Arrangements100 Percent Working Interest Until ½ Recoupment Then 1/4 Interest............................71-206, 1971-1 CB 105Depreciable Equipment Treated After Drilling Cost Recouped.................................71-207, 1971-1 CB 16069-332, 1969-1 CB 87Drilling for an Interest....................................70-657, 1970-2 CB 70Drilling for Site and Acreage...............................77-176, 1971-1 CB 77Drilling in a Partnership....................................54-42, 1954-1 CB 64Lessee Uses Lessor's Equipment...........................68-361, 1968-2 CB 264Partnership...........................................68-139, 1968-1 CB 311Recoupment of Specified Amount..........................70-336, 1970-1 CB 145Turnkey Agreement for Productive Wells Only................................................75-304, 1975-2 CB 94MiscellaneousAdvanced Minimum Royalty...............................80-70, 1980-1 CB 104Bottom Hole Contribution...............................80-153, 1980-1 CB 10 TR-8  REVENUE RULING NO. Equalization Payments on Unitized Properties...........................................68-186, 1968-1 CB 354Installment Bonus.......................................68-606, 1968-2 CB 42Production Payment Distinguished from Royalty.............................................86-119, 1986-2 CB 181Qualified Tertiary Recovery Methods.........................93-11, 1993-7 IRB 11Removal Cost of Offshore Platform.........................80-182, 1980-2 CB 167Take or Pay Contract....................................66-64, 1966-1 CB 97Take or Pay Contract Is Not a Production Payment..............................................80-48, 1980-1 CB 99