**PRESENT-LAW TAX RULES RELATING TO**DOMESTIC OIL AND GAS EXPLORATION AND PRODUCTION****AND DESCRIPTION OF H.R. 53 AND H.R. 423**
Scheduled for a Hearing

Before the

SUBCOMMITTEE ON OVERSIGHT

of the

HOUSE COMMITTEE ON WAYS AND MEANS

on February 25, 1999

Prepared By the Staff

of the

JOINT COMMITTEE ON TAXATION

February 23, 1999

JCX-8-99

**CONTENTS**

**INTRODUCTION**

**I.	PRESENT-LAW TAX RULES APPLICABLE TO DOMESTIC OIL AND GAS OPERATIONS**

	A.	Depletion

 B.	Intangible Drilling and Development Costs

	C.	Geological and Geophysical Costs

	D.	Tax Credits

			1.  Nonconventional fuels production credit

			2.  Enhanced oil recovery credit

	E.	Alternative Minimum Tax

	F.	Passive Activity Loss and Credit Rules

	G.	Sales and Exchanges of Property Interests

	H.	Net Operating Losses

**II.	DESCRIPTION OF H.R. 53 AND H.R. 423**

	A.	Description of H.R. 53 (Mr. Watkins, Mr. Thomas, Mr. McCrery, and Others):	Tax Credit for Production of Oil and Gas From Marginal Wells

	B.	Description of H.R. 423 (Mr. Thomas, Mr. Watkins, and Others):		Net Operating Loss Carrybacks for Certain Oil and Gas Losses

**INTRODUCTION**

	This document,(1)prepared by the staff of the Joint Committee on Taxation, provides anoverview of various present-law tax provisions that relate to the exploration for, and theproduction of, crude oil and natural gas located within the United States (Part I).  Part II of thedocument provides a description of two bills related to the tax treatment of oil and gas: H.R. 53(Messrs. Watkins, Thomas, McCrery, and others) and H.R. 423 (Messrs. Thomas, Watkins andothers).  H.R. 53 would provide a tax credit for production of oil and gas from marginal wells,and H.R. 423 would provide five-year carryback for certain oil and gas net operating losses.  

	The Subcommittee on Oversight of the House Committee on Ways and Means hasscheduled a public hearing on tax proposals to increase domestic oil and gas production onFebruary 25, 1999. 

**I.  PRESENT-LAW TAX RULES APPLICABLE TO DOMESTIC OIL AND GAS OPERATIONS**

**A.  Depletion**

**General rules**

	Depletion, like depreciation, is a form of capital cost recovery.  In both cases, the taxpayeris allowed a deduction in recognition of the fact that an asset--in the case of depletion for oil orgas interests, the mineral reserve itself--is being expended in order to produce income. Certaincosts incurred prior to drilling an oil or gas property are recovered through the depletiondeduction.  These include costs of acquiring the lease or other interest in the property andgeological and geophysical costs (in advance of actual drilling).

	Depletion is available to any person having an economic interest in a producing property.Treasury Department regulations state that an economic interest is possessed in every case inwhich the taxpayer has acquired by investment any interest in minerals in place, and secures, byany form of legal relationship, income derived from the extraction of the mineral, to which it mustlook for a return of its capital.(2)  Thus, for example, both working interests and royalty interests inan oil- or gas-producing property constitute economic interests, thereby qualifying the interestholders for depletion deductions with respect to the property.  A taxpayer who has no capitalinvestment in the mineral deposit does not possess an economic interest merely because through acontractual relation it possesses a mere economic or pecuniary advantage derived fromproduction.

	Two methods of depletion are currently allowable under the Internal Revenue Code (the"Code"): (1) the cost depletion method, and (2) the percentage depletion method (secs. 611-613).Under the cost depletion method, the taxpayer deducts that portion of the adjusted basis of thedepletable property which is equal to the ratio of units sold from that property during the taxableyear to the number of units remaining as of the end of taxable year plus the number of units soldduring the taxable year.  Thus, the amount recovered under cost depletion may never exceed thetaxpayer's basis in the property.

	Under the percentage depletion method generally, 15 percent of the taxpayer's grossincome from an oil- or gas-producing property is allowed as a deduction in each taxable year (sec.613A(c)).  The amount deducted generally may not exceed 100 percent of the net income fromthat property in any year (the "net-income limitation") (sec. 613(a)).(3)  Additionally, the percentagedepletion deduction for all oil and gas properties may not exceed 65 percent of the taxpayer'soverall taxable income (determined before such deduction and adjusted for certain loss carrybacksand trust distributions) (sec. 613A(d)(1)).(4)  Because percentage depletion, unlike cost depletion, iscomputed without regard to the taxpayer's basis in the depletable property, cumulative depletiondeductions may be greater than the amount expended by the taxpayer to acquire or develop theproperty.

	A taxpayer is required to determine the depletion deduction for each oil or gas propertyunder both the percentage depletion method (if the taxpayer is entitled to use this method) and thecost depletion method.  If the cost depletion deduction is larger, the taxpayer must utilize thatmethod for the taxable year in question (sec. 613(a)).

**Limitation of oil and gas percentage depletion to independent producers and royalty owners**

	The Tax Reduction Act of 1975 (the "1975 Act") repealed the deduction for percentagedepletion with respect to much oil and gas production.  Following the 1975 Act, only independentproducers and royalty owners (as contrasted to integrated oil companies) are allowed to claimpercentage depletion.  Percentage depletion for eligible taxpayers is allowed only with respect toup to 1,000 barrels of average daily production of domestic crude oil or an equivalent amount ofdomestic natural gas (sec. 613A(c)).(5)  For producers of both oil and natural gas, this limitationapplies on a combined basis.  All production owned by businesses under common control andmembers of the same family must be aggregated (sec. 613A(c)(8)); each group is then treated asone producer for application of the 1,000-barrel limitation.

	For purposes of the percentage depletion allowance, an independent producer is anyproducer that is not a "retailer" or "refiner."  A retailer is any person that directly, or through arelated person, sells oil or natural gas or any product derived therefrom (1) through any retailoutlet operated by the taxpayer or related person, or (2) to any person that is obligated to marketor distribute such oil or natural gas (or product derived therefrom) under the name of the taxpayeror the related person, or that has the authority to occupy any retail outlet owned by the taxpayer ora related person (sec. 613A(d)(2)).  Bulk sales of crude oil and natural gas to commercial orindustrial users, and bulk sales of aviation fuel to the Department of Defense, are not treated asretail sales for this purpose.  Further, a person is not a retailer within the meaning of this provisionif the combined gross receipts of that person and all related persons from the retail sale of oil,natural gas, or any product derived therefrom do not exceed $5 million for the taxable year.

	A refiner is any person that directly or through a related person engages in the refining ofcrude oil, but only if such person or related person has a refinery run in excess of 50,000 barrelsper day on any day during the taxable year (sec. 613A(d)(4)).

	In addition to the independent producer and royalty owner exception, certain sales ofnatural gas under a fixed contract in effect on February 1, 1975, and certain natural gas fromgeopressured brine,(6) are eligible for percentage depletion, at rates of 22 percent and 10 percent,respectively.  These exceptions apply without regard to the 1,000-barrel-per-day limitation andregardless of whether the producer is an independent producer or an integrated oil company.

	Before enactment of the Omnibus Budget Reconciliation Act of 1990 (the "1990 Act"), ifan interest in a proven oil or gas property was transferred (subject to certain exceptions), theproduction from such interest did not qualify for percentage depletion.(7)  The 1990 Act repealedthe limitation on claiming percentage depletion on transferred properties effective for propertytransfers occurring after October 11, 1990.

**Percentage depletion on marginal production**

	The 1990 Act also created special percentage depletion provisions for oil and gasproduction from so-called marginal properties held by independent producers or royalty owners(sec. 613A(c)(6)).  Under this provision, the statutory percentage depletion rate is increased (fromthe general rate of 15 percent) by one percent for each whole dollar that the average price of crudeoil (as determined under the provisions of the nonconventional fuels production credit of section29) for the immediately preceding calendar year is less than $20 per barrel.  In no event may therate of percentage depletion under this provision exceed 25 percent for any taxable year. Theincreased rate applies for the taxpayer's taxable year which immediately follows a calendar yearfor which the average crude oil price falls below the $20 floor.  To illustrate the application of thisprovision, the average price of a barrel of crude oil for calendar year 1997 (the most recent yearfor which a determination is available) was $17.24.(8)  Thus, the  percentage depletion rate forproduction from marginal wells was increased to 17 percent for taxable years beginning in 1998.

	The Code defines the term "marginal production" for this purpose as domestic crude oil ordomestic natural gas which is produced during any taxable year from a property which (1) is astripper well property for the calendar year in which the taxable year begins, or (2) is a propertysubstantially all of the production from which during such calendar year is heavy oil (i.e., oil thathas a weighted average gravity of 20 degrees API or less corrected to 60 degrees Fahrenheit) (sec.613A(c)(6)(D)).  A stripper well property is any oil or gas property which produces a dailyaverage of 15 or less equivalent barrels of oil and gas per producing oil or gas well on suchproperty in the calendar year during which the taxpayer's taxable year begins (sec.613A(c)(6)(E)).(9)
	The determination of whether a property qualifies as a stripper well property is madeseparately for each calendar year.  The fact that a property is or is not a stripper well property forone year does not affect the determination of the status of that property for a subsequent year.Further, the stripper well property determination is made by a taxpayer for each separate propertyinterest (as defined under section 614) held by the taxpayer during a calendar year.  Thedetermination is based on the total amount of production from all producing wells that are treatedas part of the same property interest of the taxpayer.  A property qualifies as a stripper wellproperty for a calendar year only if the wells on such property were producing during that periodat their maximum efficient rate of flow.

	If a taxpayer's property consists of a partial interest in one or more oil- or gas-producingwells, the determination of whether the property is a stripper well property or a heavy oil propertyis made with respect to total production from such wells, including the portion of total productionattributable to ownership interests other than the taxpayer's.  If the property satisfies therequirements of a stripper well property, then that person receives the benefits of this provisionwith respect to its allocable share of the production from the property for its taxable year thatbegins during the calendar year in which the property so qualifies.

	The allowance for percentage depletion on production from marginal oil and gasproperties is subject to the 1,000-barrel-per-day limitation discussed above.  Unless a taxpayerelects otherwise, marginal production is given priority over other production for purposes ofutilization of that limitation.

**B.  Intangible Drilling and Development Costs**

**In general**

	In general, costs that benefit future periods must be capitalized and recovered over those periods for income tax purposes, rather than being expensed in the period the costs are incurred.Special rules are provided, however, for the treatment of intangible drilling and developmentcosts ("IDCs").  Under these special rules, an operator or working interest owner (i.e., a personthat holds a working or operating interest in any tract or parcel of land either as a fee owner orunder a lease or any other form of contract granting working or operating rights) that pays orincurs IDCs in the development of an oil or gas property located in the United States, may electeither to expense or capitalize those costs (sec. 263(c)).

	IDCs include all expenditures made by an operator for wages, fuel, repairs, hauling,supplies, etc., incident to and necessary for the drilling of wells and the preparation of wells forthe production of oil and gas.  In addition, IDCs include the cost to operators of any drilling ordevelopment work (excluding amounts payable only out of production or gross or net proceedsfrom production, if the amounts are depletable income to the recipient, and amounts properlyallocable to the cost of depreciable property) done by contractors under any form of contract(including a turnkey contract).  Such work includes labor, fuel, repairs, hauling, and supplieswhich are used in the drilling, shooting, and cleaning of wells; in such clearing of ground,draining, road making, surveying, and geological works (as are necessary in preparation for thedrilling of wells); and in the construction of such derricks, tanks, pipelines, and other physicalstructures as are necessary for the drilling of wells and the preparation of wells for the productionof oil and gas. Generally, IDCs do not include expenses for items which have a salvage value(such as pipes and casings), or items which are part of the acquisition price of an interest in theproperty.(10)

	If an election to expense IDCs is made, the taxpayer deducts the amount of the IDCs as anexpense in the taxable year the cost is paid or incurred.  Generally, if IDCs are not expensed, butare capitalized, they may be recovered through depletion or depreciation, as appropriate; or in thecase of a nonproductive well ("dry hole"), they may be deducted, at the election of the operator.(11) In the case of an integrated oil company that has elected to expense IDCs, 30 percent of the IDCson productive wells must be capitalized and amortized over a 60-month period (sec.291(b)(1)(A)).(12)

	Notwithstanding the fact that a taxpayer has made the election to deduct IDCs, the Codeprovides an additional election under which the taxpayer is allowed to capitalize and amortizecertain IDCs over a 60-month period beginning with the month the expenditure was paid orincurred (sec. 59(e)(1)).  This rule applies on an expenditure-by-expenditure basis; that is, for anyparticular taxable year, a taxpayer may deduct some portion of its IDCs and capitalize the restunder this provision.  This allows the taxpayer to reduce or eliminate the IDC adjustments orpreferences under the alternative minimum tax.

	The election to deduct IDCs applies only to those IDCs associated with domesticproperties.(13)  For this purpose, the United States includes certain wells drilled offshore.(14)

**Exemption from uniform capitalization rules**

	The uniform capitalization rules, which were enacted as part of the Tax Reform Act of1986, require certain direct and indirect costs allocable to property to be included in inventory orcapitalized as part of the basis of such property (sec. 263A).  In general, the uniform capitalizationrules apply to real and tangible personal property produced by the taxpayer or acquired for resale. Pursuant to a special exception, these rules do not apply to IDCs incurred with respect to oil orgas wells which are otherwise deductible under the Code (sec. 263A(c)(3)).

**C.  Geological and Geophysical Costs**

**In general**

	Under the Code, no current deduction is allowed for any amount paid for new buildings orfor permanent improvements or betterments made to increase the value of any property or estate(sec. 263(a)).  The regulations define capital amounts to include amounts paid or incurred (1) toadd to the value, or substantially prolong the useful life, of property owned by the taxpayer or (2)to adapt property to a new or different use.(15)

	The proper income tax treatment of geological and geophysical expenditures ("G&Gcosts") has been the subject of a number of court decisions and administrative rulings. G&G costsare incurred by the taxpayer for the purpose of obtaining and accumulating data that will serve asa basis for the acquisition and retention of mineral properties by taxpayers exploring for minerals.Courts have ruled that such costs are capital in nature and are not deductible as ordinary andnecessary business expenses.(16)  Accordingly, the costs attributable to such exploration areallocable to the cost of the property acquired or retained.(17)  The term "property" is used in thiscase in the sense of an interest in a property as defined in the Code (sec. 614), and includes aneconomic interest in a tract or parcel of land notwithstanding that a mineral deposit has not beenestablished or proven at the time the costs are incurred.

**Revenue Ruling 77-188**

	In Revenue Ruling 77-188(18) (hereinafter referred to as the "1977 ruling"), the InternalRevenue Service ("IRS") provided guidance regarding the proper tax treatment of G&G costs.The ruling describes a typical geological and geophysical exploration program as containing thefollowing elements:

- It is customary in the search for mineral producing properties for a taxpayer toconduct an exploration program in one or more identifiable project areas. Eachproject area encompasses a territory that the taxpayer determines can be exploredadvantageously in a single integrated operation. This determination is made afteranalyzing certain variables such as the size and topography of the project area tobe explored, the existing information available with respect to the project area andnearby areas, and the quantity of equipment, the number of personnel, and theamount of money available to conduct a reasonable exploration program over theproject area.
- The taxpayer selects a specific project area from which geological and geophysicaldata are desired and conducts a reconnaissance-type survey utilizing variousgeological and geophysical exploration techniques that are designed to yield datathat will afford a basis for identifying specific geological features with sufficientmineral potential to merit further exploration.
- Each separable, noncontiguous portion of the original project area in which such aspecific geological feature is identified is a separate "area of interest."  Theoriginal project area is subdivided into as many small projects as there are areas ofinterest located and identified within the original project area.  If the circumstancespermit a detailed exploratory survey to be conducted without an initialreconnaissance-type survey, the project area and the area of interest will becoextensive.
- The taxpayer seeks to further define the geological features identified by the priorreconnaissance-type surveys by additional, more detailed, exploratory surveysconducted with respect to each area of interest.  For this purpose, the taxpayerengages in more intensive geological and geophysical exploration employingmethods that are designed to yield sufficiently accurate sub-surface data to afforda basis for a decision to acquire or retain properties within or adjacent to aparticular area of interest or to abandon the entire area of interest as unworthy ofdevelopment by mine or well.

	The 1977 ruling provides that if, on the basis of data obtained from the preliminarygeological and geophysical exploration operations, only one area of interest is located andidentified within the original project area, then the entire expenditure for those exploratoryoperations is to be allocated to that one area of interest and thus capitalized into the depletablebasis of that area of interest.  On the other hand, if two or more areas of interest are located andidentified within the original project area, the entire expenditure for the exploratory operations isto be allocated equally among the various areas of interest.

	If, however, from the data obtained by the exploratory operations no areas of interest arelocated and identified by the taxpayer within the original project area, then the 1977 ruling statesthat the entire amount of the G&G costs related to the exploration is deductible as a loss undersection 165 for the taxable year in which that particular project area is abandoned as a potentialsource of mineral production.

	The 1977 ruling further provides that if, on the basis of data obtained from a detailedsurvey that does not relate exclusively to any particular property within a particular area ofinterest, an oil or gas property is acquired or retained within or adjacent to that area of interest, theentire G&G exploration expenditures, including those incurred prior to the identification of theparticular area of interest but allocated thereto, are to be allocated to the property as a capital costunder section 263(a).  If more than one property is acquired or retained within or adjacent to anarea of interest, it is proper to determine the amount of the G&G costs allocable to each suchproperty by allocating the entire amount of the costs among the properties so acquired or retainedon the basis of the comparative acreage of the properties.

	If, however, no property is acquired or retained within or adjacent to that area of interest,the entire amount of the G&G costs allocable to the area of interest is deductible as a loss undersection 165 for the taxable year in which such area of interest is abandoned as a potential sourceof mineral production.

	In 1983, the IRS issued Revenue Ruling 83-105,(19) which elaborates on the positions setforth in the 1977 ruling by setting forth seven factual situations and applying the principles of the1977 ruling to those situations.  In addition, Revenue Ruling 83-105 explains what constitutes an"abandonment as a potential source of mineral production."

**D.  Tax Credits**

**1.  Nonconventional fuels production credit**

	Taxpayers that produce certain qualifying fuels from nonconventional sources are eligiblefor a tax credit ("the section 29 credit") equal to $3 per barrel or Btu oil barrel equivalent.(20)  Fuelsqualifying for the credit must be produced domestically from a well drilled, or a facility treated asplaced in service, before January 1, 1993.  The section 29 credit generally is available forqualified fuels sold to unrelated persons before January 1, 2003.

	A facility that produces gas from biomass or produces liquid, gaseous, or solid syntheticfuels from coal (including lignite) generally is treated as being placed in service before January 1,1993, if it was placed in service by the taxpayer before July 1, 1998, pursuant to a written bindingcontract in effect before January 1, 1997.  If a facility that qualifies for this binding contractexception is originally placed in service after December 31, 1992, production from the facilitymay qualify for the credit if sold to an unrelated person before January 1, 2008.

	For purposes of the credit, qualified fuels include: (1) oil produced from shale and tarsands; (2) gas produced from geopressured brine, Devonian shale, coal seams, a tight formation,or biomass (i.e., any organic material other than oil, natural gas, or coal (or any product thereof));and (3) liquid, gaseous, or solid synthetic fuels produced from coal (including lignite), includingsuch fuels when used as feedstocks.  Production attributable to a property from which gas fromDevonian shale, coal seams, geopressured brine, or a tight formation was produced in marketablequantities before 1980 does not qualify for the credit.

	The amount of the section 29 credit generally is adjusted by an inflation adjustment factorfor the calendar year in which the sale occurs. The inflation adjustment factor for the 1997 taxableyear (the most recent year for which a determination is available) was 2.0331.  Therefore, theinflation-adjusted amount of the credit for that year was $6.10 per barrel or barrel equivalent.(21) There is no adjustment for inflation in the case of the credit for sales of natural gas produced froma tight formation.  The credit begins to phase out if the annual average unregulated wellhead priceper barrel of domestic crude oil exceeds $23.50 multiplied by the inflation adjustment factor.(22) For 1997 (the most recent year for which a determination is available), the inflation adjustedthreshold for onset of the phase out was $47.78 ($23.50 x 2.0331) and the average wellhead pricefor that year was $15.98.

	The amount of the section 29 credit allowable with respect to a project is reduced by anyunrecaptured business energy tax credit (sec. 48) or enhanced oil recovery credit (sec. 43) claimedwith respect to such project.

	As with most other credits, the section 29 credit may not be used to offset alternativeminimum tax liability.  Any unused section 29 credit generally may not be carried back orforward to another taxable year; however, a taxpayer, under section 53, receives a credit for prioryear minimum tax liability to the extent that a section 29 credit is disallowed as a result of theoperation of the alternative minimum tax.  The credit is limited to what would have been theregular tax liability but for the alternative minimum tax.

**2.  Enhanced oil recovery credit**

	Taxpayers are permitted to claim a general business credit for a taxable year, whichconsists of several different components (sec. 38(a)).  One component of the general businesscredit is the enhanced oil recovery credit (sec. 43).  The general business credit for a taxable yearmay not exceed the excess (if any) of the taxpayer's net income over the greater of (1) thetentative minimum tax, or (2) 25 percent of so much of the taxpayer's net regular tax liability asexceeds $25,000.  Any unused general business credit generally may be carried back three taxableyears and carried forward 15 taxable years.

	The enhanced oil recovery credit for a taxable year is equal to 15 percent of certain costsattributable to qualified enhanced oil recovery ("EOR") projects undertaken by the taxpayer in theUnited States during the taxable year.  To the extent that a credit is allowed for such costs, thetaxpayer must reduce the amount otherwise deductible or required to be capitalized and recoveredthrough depreciation, depletion, or amortization, as appropriate, with respect to these costs.  Ataxpayer may elect not to have the enhanced oil recovery credit apply for a taxable year. 

	The amount of the enhanced oil recovery credit is reduced in a taxable year following acalendar year during which the annual average unregulated wellhead price per barrel of domesticcrude oil exceeds $28 (adjusted for inflation since 1990).(23)   For calendar year 1998, this amountwas $33.60.(24)  If the average unregulated wellhead price exceeds this amount, the credit would bereduced ratably over a $6 phase out range.

	For purposes of the credit, qualified enhanced oil recovery costs include the followingcosts which are paid or incurred with respect to a qualified EOR project: (1) the cost of tangibleproperty which is an integral part of the project and with respect to which depreciation oramortization is allowable; (2) IDCs with respect to which a taxpayer may make an election todeduct under section 263(c);(25) and (3) the cost of tertiary injectants with respect to which adeduction is allowable under section 193, whether or not chargeable to capital account.

	A qualified EOR project means any project that is located within the United States andinvolves the application (in accordance with sound engineering principles) of one or more tertiaryrecovery methods as defined under section 193(b)(3) which can reasonably be expected to resultin more than an insignificant increase in the amount of crude oil which ultimately will berecovered.  The tertiary recovery methods referred to in section 193(b)(3) generally include thefollowing nine methods which were listed in section 212.78(c) of the June 1979 Department ofEnergy regulations: miscible fluid displacement, steam-drive injection, microemulsion flooding,in situ combustion, polymer-augmented water flooding, cyclic-steam injection, alkaline flooding,carbonated water flooding, and immiscible non-hydrocarbon gas displacement, or any othermethod approved by the IRS.  In addition, for purposes of the enhanced oil recovery credit,immiscible non-hydrocarbon gas displacement generally is considered a qualifying tertiaryrecovery method, even if the gas injected is not carbon dioxide.

	A project is not considered a qualified EOR project unless the project's operator submitsto the IRS a certification from a petroleum engineer that the project meets the requirements setforth in the preceding paragraph.

	The enhanced oil recovery credit is effective for taxable years beginning after December31, 1990, with respect to costs paid or incurred in EOR projects begun or significantly expandedafter that date.

**E.  Alternative Minimum Tax**

**In general**

	A taxpayer is subject to an alternative minimum tax ("AMT") to the extent that itstentative minimum tax exceeds its regular income tax liability (sec. 55(a)).  A corporate taxpayer'stentative minimum tax generally equals 20 percent of its alternative minimum taxable income inexcess of an exemption amount.  (The marginal AMT rate for a noncorporate taxpayer is 26 or 28percent, depending on the amount of its alternative minimum taxable income above an exemptionamount.)  Alternative minimum taxable income ("AMTI") is the taxpayer's taxable incomeincreased by certain tax preferences and adjusted by determining the tax treatment of certain itemsin a manner which negates the deferral of income resulting from the regular tax treatment of thoseitems.

	The AMTI of a corporation is increased by an amount equal to 75 percent of the amountby which adjusted current earnings ("ACE") of the corporation exceed AMTI (as determinedbefore this adjustment) (sec. 56(g)).  In general, ACE means AMTI with additional adjustmentsthat generally follow the rules presently applicable to corporations in computing their earningsand profits.

**AMT treatment of depletion**

	Since the provisions of the Energy Policy Act of 1992 became fully effective, there hasbeen no AMT preference for oil and gas percentage depletion.  Before enactment of that Act, oiland gas percentage depletion deductions in excess of the taxpayer's basis in the property were anAMT preference.

**AMT treatment of IDCs**

	Also as discussed above, in computing its regular tax, a taxpayer who pays or incurs IDCsin the development of domestic oil or gas properties may elect to either expense or capitalize theseamounts.  The difference between the amount of a taxpayer's IDC deductions and the amountwhich would have been currently deductible had IDCs been capitalized and recovered over a10-year period may constitute an item of tax preference for the AMT to the extent that thisamount exceeds 65 percent of the taxpayer's net income from oil and gas properties for the taxableyear (the "excess IDC preference") (sec. 57(a)(2)).

	For taxpayers other than integrated oil companies, the Energy Policy Act of 1992 repealedthe excess IDC preference for IDCs related to oil and gas wells for taxable years beginning after1992 (sec. 57(a)(2)(E)).  The repeal of the excess IDC preference, however, may not result in thereduction of the amount of the taxpayer's AMTI by more than 40 percent of the amount that thetaxpayer's AMTI would have been had the excess IDC preference not been repealed.

	In addition, for purposes of computing the an integrated oil company's ACE adjustment tothe AMT, IDCs are capitalized and amortized over the 60-month period beginning with the monthin which they are paid or incurred (sec. 56(g)(4)(D)(i)).  The ACE preference does not apply toindependent oil and gas producers since enactment of the Energy Policy Act of 1992.

**F.  Passive Activity Loss and Credit Rules**

	A taxpayer's deductions from passive trade or business activities, to the extent they exceedincome from all such passive activities of the taxpayer (exclusive of portfolio income), generallymay not be deducted against other income (sec. 469).(26)  Thus, for example, an individual taxpayergenerally may not deduct losses from a passive activity against income from wages.  Lossessuspended under this "passive activity loss" limitation are carried forward and treated asdeductions from passive activities in the following year, and thus may offset any income frompassive activities generated in that later year.  Suspended losses from a passive activity may bededucted in full when the taxpayer disposes of its entire interest in that activity to an unrelatedparty in a transaction in which all realized gain or loss is recognized.  An activity generally istreated as passive i f the taxpayer does not materially participate in it.  A taxpayer is treated asmaterially participating in an activity only if the taxpayer is involved in the operations of theactivity on a basis which is regular, continuous, and substantial.

	A working interest in an oil or gas property generally is not treated as a passive activity,whether or not the taxpayer materially participates in the activities related to that property (sec.469(c)(3) and (4)).  This exception from the passive activity rules does not apply if the taxpayerholds the working interest through an entity which limits the liability of the taxpayer with respectto the interest.  In addition, if a taxpayer has any loss for any taxable year from a working interestin an oil or gas property which is treated pursuant to this working interest exception as a losswhich is not from a passive activity, then any net income from such property (or any property thebasis of which is determined in whole or in part by reference to the basis of such property) for anysucceeding taxable year is treated as income of the taxpayer which is not from a passive activity.

	Similar limitations apply to the utilization of tax credits attributable to passive activities(sec. 469(a)(1)(B)).  Thus, for example, the passive activity rules (and, consequently, the oil andgas working interest exception to those rules) apply to the nonconventional fuels production creditand the enhanced oil recovery credit.  However, if a taxpayer has net income from a workinginterest in an oil and gas property which is treated as not arising from a passive activity, then anytax credits attributable to the interest in that property are treated as credits not from a passiveactivity (and, thus, not subject to the passive activity credit limitation) to the extent that theamount of such credits does not exceed the regular tax liability of the taxpayer for the taxable yearwhich is allocable to such net income. 

**G.  Sales and Exchanges of Property Interests**

	Under present law, individual taxpayers are subject to a maximum statutory income taxrate of 39.6 percent.  If an individual recognizes capital gains, however, the gains generally aresubject to a maximum tax rate of 20 percent.  There currently is no differential between the ratesof taxation of capital gains and ordinary income in the case of corporate taxpayers.

	Gain recognized from the disposition of an interest in an oil or gas property generally ischaracterized as capital gain.  The Code contains a special recapture provision, however, whichmandates that in certain cases a portion of any gain is to be treated as ordinary income and not ascapital gain (sec. 1254).  Specifically, the Code provides that if a taxpayer disposes of "section1254 property" that was placed in service after 1986, then the lesser of (1) the gain recognized onthe disposition or (2) the aggregate amount of (a) depletion deductions which resulted in areduction in the basis of the property disposed of and (b) IDCs deducted pursuant to an electionunder section 263(c) and which, but for the deduction, would have been included in the adjustedbasis of the property, is characterized as ordinary income.(27)  For this purpose, the term "section1254 property" means any property (within the meaning of sec. 614) if any IDCs are properlychargeable to such property or the adjusted basis of such property includes adjustments fordepletion deductions.

**H.  Net Operating Losses**

	A net operating loss ("NOL") is generally the amount by which business deductions of ataxpayer exceed business gross income.  In general, an NOL may be carried back two years andcarried forward 20 years to offset taxable income in such years.(28)  A carryback of an NOL resultsin the refund of Federal income tax for the carryback year.  A carryforward of an NOL reducesFederal income tax for the carryforward year.  Special NOL carryback rules apply to (1) casualtyand theft losses of individual taxpayers, (2) Presidentially declared disasters for taxpayersengaged in a farming business or a small business, (3) real estate investment trusts, (4) specifiedliability losses, (5) excess interest losses, and (6) farm losses.

**II.  DESCRIPTION OF H.R. 53 AND H.R. 423**

**A.  Description of H.R. 53 (Mr. Watkins, Mr. Thomas, Mr. McCrery, and Others):**Tax Credit for Production of Oil and Gas From Marginal Wells****Description of the Bill**
	H.R. 53 would create a new income tax credit for the production of crude oil and naturalgas from marginal wells.  The credit would be a component of the general business credit (sec.38).  The marginal well production credit for any taxable year would equal the product of (1) thecredit amount, and (2) the qualified crude oil production and the qualified natural gas productionwhich is attributable to the taxpayer.  The "credit amount" would be $3 per barrel of qualifiedcrude oil production and 50 cents per 1,000 cubic feet of qualified natural gas production. "Qualified crude oil production" and "qualified natural gas production" would be defined as crudeoil or natural gas which was produced from a marginal well.

	The term "marginal well" would be defined as a domestic well which during the taxableyear has marginal production.  Marginal production would be defined as domestic crude oil ordomestic natural gas which is produced during any taxable year from a property which (1) was astripper well property for the calendar year in which the taxable year begins, or (2) was a propertysubstantially all of the production of which during the calendar year was heavy oil (i.e., oil thathas a weighted average gravity of 20 degrees API or less corrected to 60 degrees Fahrenheit).  Astripper well property would be defined as an oil or gas property which produces a daily averageof 15 or less equivalent barrels of oil and gas per producing well on the property in the calendaryear during which the taxpayer's taxable year begins.

	Under the bill, the credit amount would be phased out as oil and gas prices increased. This would phase out the credit for barrels of qualified crude oil with reference price between $14and $17 and qualified natural gas with reference price between $1.56 and $1.89.(29)  In taxableyears beginning in a calendar year after 1999, these dollar amounts would be indexed forinflation.  The reference price for the calendar year for qualified crude oil would be the TreasuryDepartment's estimate of the annual average wellhead price per barrel for all domestic crude oil,or in the area of natural gas, the Treasury's estimate of the annual average wellhead price per1,000 cubic feet for all domestic natural gas.

	Crude oil or natural gas produced during any taxable year from any well would not betreated as qualified crude oil production or qualified natural gas production to the extentproduction from the well during the taxable year exceeds 1,095 barrels or barrel equivalents.(30)

	The credit could be claimed only on production which was attributable to the holder of anoperating interest.  In the case of a marginal well in which there is more than one owner ofoperating interests in the well, and the crude oil or natural gas production exceeds the limitations,then crude oil or natural gas production would be determined on the basis of the ratio which thetaxpayer's revenue interest in the production bears to the aggregate revenue interests of alloperating interest owners in the production.

	The proposed credit would not be allowed for production from any well if the productionalso qualified for the nonconventional fuels production credit unless the taxpayer elected not toclaim the nonconventional fuels credit (sec. 29) with respect to the well.  The marginal wellproduction credit also would be permitted to offset, in full, the regular tax and the alternativeminimum tax.  Any unused credits generally could be carried back 10 years and carried forward20 years.

**Effective Date**

	The provisions of the bill would apply to production after the date of enactment.

**B.  Description of H.R. 423 (Mr. Thomas, Mr. Watkins, and Others):nNet Operating Loss Carryback for Certain Oil and Gas Losses**

**Description of the Bill**

	H.R. 423 would provide a special five-year carryback for certain eligible oil and gaslosses.  The carryforward period would remain 20 years.  An "eligible oil and gas loss" would bedefined as the lesser of (1) the amount which would be the taxpayer's NOL for the taxable year ifonly income and deductions attributable to operating mineral interests in oil and gas wells weretaken into account, or (2) the amount of such net operating loss for such taxable year.  Incalculating the amount of a taxpayer's NOL carrybacks, the portion of the NOL that would beattributable to an eligible oil and gas loss would be treated as a separate NOL and taken intoaccount after the remaining portion of the NOL for the taxable year.

	A taxpayer could elect to forgo the five-year carryback period for an eligible oil and gasloss.  The election to forgo the five-year carryback period would be made in the mannerprescribed by the Treasury Department and would have to be made by the due date of the return(including extensions) for the year of the loss.  The election would be irrevocable.  If a taxpayerelected to forgo the five-year carryback period, then the eligible oil and gas losses would besubject to the rules that otherwise have applied under section 172 absent the five-year rule underthe bill.

**Effective Date**

	The provisions of the bill would apply to NOLs arising in taxable years beginning afterDecember 31, 1997.

**FOOTNOTES**

1.        This document may be cited as follows: Joint Committee on Taxation,*Present-Law TaxRules Relating to Domestic Oil and Gas Exploration and Production and Description of H.R. 53and H.R. 423* (JCX-8-99), February 23, 1999.

2.        Treas. Reg. sec. 1.611-1(b)(1).
3.        By contrast, for any other mineral qualifying for the percentage depletion deduction, suchdeduction may not exceed 50 percent of the taxpayer's taxable income from the depletableproperty.  A similar 50-percent net-income limitation applied to oil and gas properties fortaxable years beginning before 1991.  Section 11522(a) of the Omnibus Budget ReconciliationAct of 1990 prospectively changed the net-income limitation threshold to 100 percent only foroil and gas properties, for taxable years beginning after 1990.  Moreover, the Taxpayer ReliefAct of 1997 suspended the 100-percent net-income limitation for marginal wells for taxableyears beginning after December, 31, 1997, and before January 1, 2000.
4.        Amounts disallowed as a result of this rule may be carried forward and deducted insubsequent taxable years, subject to the 65-percent taxable income limitation for those years.
5.        As originally enacted, the depletable oil quantity was 2,000 barrels of average dailyproduction. This was gradually phased down to 1,000 barrels of average daily production for1980 and thereafter. The 1975 Act also phased down the percentage depletion rate from 22percent in 1975 to 15 percent in 1984 and thereafter.
6.        This exception is limited to wells the drilling of which began between September 30, 1978,and January 1, 1984.
7.        The exceptions to this rule included transfers at death, certain transfers to controlledcorporations, and transfers between controlled corporations or other business entities.
8.        IRS Notice 98-42, 1998-33 I.R.B. 12.
9.        The amount of equivalent barrels is computed as the sum of (1) the number of barrels ofcrude oil produced, and (2) the number of cubic feet of natural gas produced divided by 6,000. If a well produced 10 barrels of crude oil and 12,000 cubic feet of natural gas, its equivalentbarrels produced would equal 12 (i.e., 10 + (12,000 / 6,000)).

10.        Treas. Reg. sec. 1.612-4(a).
11.        Treas. Reg. sec. 1.612-4(b)(4).
12.        The IRS has ruled that if a company that has capitalized and begun to amortize IDCs overa 60-month period pursuant to section 291 ceases to be an integrated oil company, it may notimmediately write off the unamortized portion of the capitalized IDCs, but instead mustcontinue to amortize the IDCs so capitalized over the 60-month amortization period. (Rev. Rul.93-26, 1993-1 C.B.50.)
13.        In the case of IDCs paid or incurred with respect to an oil or gas well located outside of theUnited States, the costs, at the election of the taxpayer, are either (1) included in adjusted basisfor purposes of computing the amount of any deduction allowable for cost depletion or (2)capitalized and amortized ratably over a 10-year period beginning with the taxable year suchcosts were paid or incurred (sec. 263(i)).
14.        The term "United States" for this purpose includes the seabed and subsoil of thosesubmarine areas that are adjacent to the territorial waters of the United States and over which theUnited States has exclusive rights, in accordance with international law, with respect to theexploration and exploitation of natural resources (i.e., the Continental Shelf area) (sec. 638).
15.        Treas. Reg. sec. 1.263(a)-(1)(b).
16.        See, e.g., Schermerhorn Oil Corporation 46 B.T.A. 151 (1942).
17.        By contrast, section 617 of the Code permits a taxpayer to elect to deduct certainexpenditures incurred for the purpose of ascertaining the existence, location, extent, or quality ofany deposit of ore or other mineral (but not oil and gas). These deductions are subject torecapture if the mine with respect to which the expenditures were incurred reaches the producingstage.
18.        1977-1 C.B. 76.
19.        1983-2 C.B. 51.
20.        A barrel-of-oil equivalent generally means that amount of the qualifying fuel which has aBtu (British thermal unit) content of 5.8 million.
21.        IRS Notice 98-28, 1998-19 I.R.B. 7.
22.        IRS Notice 98-28, 1998-19 I.R.B. 7. 
23.        The average per-barrel price of crude oil for this purpose is determined under the samemanner as it is for purposes of the section 29 credit.
24.        IRS Notice 98-41, 1998-33 I.R.B. 12. 
25.        In the case of an integrated oil company, the credit base includes those IDCs which thetaxpayer is required to capitalize under section 291(b)(1).
26.        This provision applies to individuals, estates, trusts, personal service corporations, andcertain closely held corporations. 
27.        For dispositions of property placed in service before 1987, taxpayers are not required torecapture depletion deductions and are required to recapture IDC deductions only in excess ofthe amounts which would have been deductible as depletion if the IDCs had been capitalized.
28.       A taxpayer could elect to forgo the carryback of an NOL.
29.       The  reference price for a taxable year would be the reference price for the calendar yearpreceding the calendar year in which the taxable year begins.
30.       "Barrel equivalent" means, with respect to natural gas, a conversion ratio of 6,000 cubicfeet of natural gas to one barrel of crude oil.  The annual barrel limitation would be reducedproportionately to reflect a taxpayer's short taxable year and also to reflect wells not inproduction the entire taxable year.****