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Various Structures for ShiftingSection 29 Credits from Producer to Investor

Dennis J. GrindingerThompson & Knight, P.C.

Dallas, Texas

Synopsis§ 13.01. Introduction. ....................................................................... 386§ 13.02. Why Buy Section 29 Properties: Benefits of Ownership

and Potential Reductions to Investor’s Shareof Section 29 Credits. ......................................................... 387[1] — Credits Provide High After Tax Yields; Reduce

Regular Income Tax on Dollar-for-Dollar Basis ...... 387[2] — Key Limitation on Investor’s Use of Section 29

Tax Credits: the Annual Credit Ceiling Amountunder Section 29(b)(6). ............................................. 389

[3] — Theoretical Risk: Reduction from Phase-outof the Credit. ............................................................. 391

[4] — Other Risk in Credit Amount: Reductions fromGovernment Subsidies, Grants, Tax-exemptFinancing, and Other Tax Credits. ............................ 391

§ 13.03. Representations Regarding Qualifying the PropertyObtained from the Seller: Statutory Requirementsfor Eligibility. ...................................................................... 393[1] — Source of the Production: Qualified

Fuel Requirement. ..................................................... 393[2] — Ownership Requirement. .......................................... 396[3] — Sharing Credits Among Investors: Apportioning

Section 29 Credits Between Holdersof Economic Interests. .............................................. 397

[4] — Drilling Requirement. ............................................... 399[5] — Prior Production Limitation. ..................................... 401[6] — Sale Requirement. ..................................................... 402

§ 13.04. Passive Activity Limitations. ............................................. 404§ 13.05. Pay-As-You-Go Structures; Leveraged Acquisitions

of Section 29 Properties. .................................................... 405[1] — Partnership with Special Allocations. ....................... 413[2] — Royalty Trust Holding Qualifying Interest. .............. 415

§ 13.06. Conclusion. ......................................................................... 416

Cite as 17 E. Min. L. Inst. ch. 13 (1997)

Chapter 13

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§ 13.01. Introduction.Investors searching for high after-tax yields have rediscovered oil and

gas acquisitions, in large part due to the tax incentive provided by thesection 29 credit.1 For the first 10 years of its existence, the section 29credit was beset by uncertainty arising from the loose language of thestatute. Tax practitioners struggled with technical questions regarding (1)which properties qualified, (2) which taxpayers were eligible and whetherthe credit could be shared, and (3) how the potential reductions couldapply.2 In addition to statutory uncertainty, the legislative history of section29 provides only limited guidance. Finally, the Internal Revenue Service(the “Service”) declined to issue any regulatory guidance under section29,3 and, while private rulings have proliferated under section 29,4 it isuncertain whether such private rulings can be relied on as “substantialauthority.”5 As a result, taxpayers were forced to rely on their tax advisor

1 The section 29 credit was passed into law on April 2, 1980, as part of the Crude Oil

Windfall Profit Tax Act of 1980, Pub. L. No. 96-223, 96th Cong., 2d Sess. § 231 (1980).The reference to section 44D is to the Code in effect in 1980. Section 44D was redesignatedas section 29 in 1984. See Pub. L. 98-369, 98th Cong., 2d Sess. § 471 (1984). Unlessotherwise indicated, all section references are to the Internal Revenue Code of 1986 (26U.S.C.), as amended (the “Code”).2 For an empherical analysis of the effectiveness of the section 29 credit in achieving the

stated congressional goals see Kiss, Robert M. and Kattelus, Susan C., “The Effectivenessof the Section Fuel from a Nonconventional Source Credit,” 44 Oil & Gas Tax Q. 267(1996).3 The lack of regulatory guidance together with the chilling effect of various failed oiland gas partnerships from the early 1980s may have caused many investors to shy awayfrom this investment. This chilling effect also may have been supplemented recently by

the issuance of the partnership anti-abuse regulations.4 From the mid-1980s, the Service has attempted to counterbalance this lack of regulatoryguidance by issuing numerous private rulings. See footnote 6, infra. Most of these privaterulings have tended to address questions as to qualification of the property rather than thestructure of the proposed transaction.5 See I.R.C. § 6662 and Treas. Reg. § 1.6662-4(d). Although each letter ruling states that

taxpayers may not use or cite the ruling letter as precedent, Treas. Reg. § 1.6662-4(d)(3)(iii)provides that private letter rulings are authority for purposes of determining whetherthere is substantial authority for the tax treatment of an item.

§ 13.01

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with respect to issues arising from the interworkings of the section 29credit.6

Recently, the Service has begun issuing private rulings regardingtransactional structures for shifting the eligibility for the tax credits fromproducer to investor. This chapter will discuss these rulings and the issuesarising under the “pay-as-you-go” structure addressed in these rulings.This chapter will also discuss briefly possible alternatives to the “pay-as-you-go” arrangement. To assist the reader’s understanding of this area,this chapter will first discuss the benefits arising from the ownership ofsection 29 credit properties (and why producers are willing to sell theseproperties). Second, this chapter will review the requirements for eligibilityfor the section 29 credit (and the type of representations regarding suchrequirements that buyers usually obtain from sellers).

§ 13.02. Why Buy Section 29 Properties: Benefitsof Ownership and Potential Reductionsto Investor’s Share of Section 29 Credits.

This section of the chapter will discuss the benefits of owning section29 properties. In addition, this section will briefly discuss the potentialreductions to an investor’s use of the section 29 credit, and why producersare unable to benefit directly from ownership of section 29 properties.Finally, this section of the chapter will discuss how buyers and sellersshare the risk as to the potential application of these reductions.

[1] — Credits Provide High After-Tax Yields; ReduceRegular Income Tax on Dollar-for-Dollar Basis.

The high after-tax yield in section 29 deals is derived from the amountby which the section 29 tax credit reduces investors’s regular income tax.Each dollar of section 29 credit reduces the investor’s regular federalincome tax by a dollar. For 1995, the section 29 credit was $1.0055 perMMBtu (except for the credit for tight formation gas, which remains

6 The Service has issued numerous private rulings (80 over the last 10 years). However,there have been few public rulings or pronouncements with regard to section 29

transactions.

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constant at approximately $.52 per MMBtu).7 The amount of the creditper MMBtu increases each year with inflation.8 Thus, an investor is ableto reduce his regular federal income tax by approximately $1.00 for eachMMBtu allocated to such investor.

The purchase price paid by the investor (calculable either per MMBtuor for the entire property) can be separated between the “hydrocarbonvalue” and the “credit value.” The hydrocarbon value is determined basedon (i) the investor’s share of the expected production stream (typicallyestablished by a reservoir engineer), (ii) the expected price escalation ofthe hydrocarbon, and (iii) an appropriate discount rate (taking intoconsideration the unique aspects of the particular reservoir or area thereof).This methodology is commonly utilized throughout the oil and gas industryto determine a property’s market value.9 In section 29 deals, the amountpaid for the hydrocarbon value is usually paid in cash at closing. This

7 I.R.C. § 29(b)(2). Section 29(d)(2)(B) provides that the inflation adjustment factor isdetermined annually by dividing the GNP implicit price deflator for the calendar year by

the GNP implicit price deflator for 1979. The inflation adjustment factors, published bythe Service in the Federal Register, for 1993, 1994 and 1995 are 1.8918, 1.9207, and1.9439, respectively. See I.R.S. Notice, 59 F.R. 16,259 (April 6, 1994), I.R.S. Notice 95-26, 1995-1 C.B. 305 and I.R.S. Notice 96-29, 1996-19 I.R.B. 7. Accordingly, the statutoryamounts of the section 29 credit for such years are $5.68 per BOE. ($.98 per MMBtu) in1993, $5.76 per BOE ($.99 per MMBtu) in 1994, and $5.83 per BOE ($1.01 per MMBtu)

in 1995.8 Under a formula prescribed in section 29, the “statutory amount” is multiplied by the“barrel of oil equivalent” of the qualified fuel sold by the taxpayer during the taxableyear. The “statutory amount” of the credit is determined by multiplying (a) $3.00 (thefixed dollar amount set forth in section 29(a)(1)) by (b) the inflation adjustment factorprescribed in section 29(b)(2). Section 29(d)(2)(A) provides that the Service must publish

the inflation adjustment factor by April 1 of each year, although the Service was severaldays late regarding the 1995 information. The inflation adjustment factor is used indetermining the statutory amount of the credit for the preceding calendar year. For theinflation adjustment factors applicable to the last three years, see footnote 4 infra. The“barrel of oil equivalent” is the amount of fuel which has a Btu content of 5.8 million. See

I.R.C. § 29(d)(5).9 Components used to determine the hydrocarbon value of a property can be taken directlyfrom various established exchanges or, alternatively, from established pricing hubs orindices.

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“upfront cash payment” is relatively small in comparison to the creditvalue portion of the purchase price.

The credit value is determined based on (i) the investor’s share of theexpected production stream of the qualifying hydrocarbon, (ii) the expectedBtu content of the qualifying hydrocarbon, and (iii) an appropriate discountrate (taking into consideration the unique tax aspects of the particularstructure being utilized and the potential impact of inflation adjustmentsto the credit). Typically, investors purchase the credit stream on a section29 property for less than the actual credit value (e.g., 75 percent of thecredit amount, discounted further to reflect the time value of money, ifpaid in a lump sum at closing). In most section 29 transactions, the creditvalue is substantially greater than the hydrocarbon value. Because theafter-tax yield is directly related to the purchase price and given the relativevalues of each of the two components, the amount paid for the creditvalue is critical to both buyer and seller in section 29 transactions.

[2] — Key Limitation on Investor’s Use of Section 29 TaxCredits: the Annual Credit Ceiling Amount UnderSection 29(b)(6).

The number of investors willing to invest large sums on money insection 29 properties is limited, given the annual credit ceiling limitationunder Code Section 29(b)(6). For each tax year, an investor’s regularfederal income tax can be reduced by section 29 credits up to the investor’scredit ceiling amount for such year. An investor’s credit ceiling amountfor a tax year is the excess of (a) the investor’s regular federal income tax(reduced by any possession tax credits or credits for testing certain drugs)over (b) such investor’s tentative minimum tax for such year.10 If theinvestor’s share of section 29 credits exceeds the credit ceiling, the excess

10 I.R.C. § 29(b)(6). For purposes of this calculation, a taxpayer’s “regular tax” isequal to his tax liability under section 1 (or section 11) of the Code reduced by the sumof (i) the credits allowable under subpart A of the Code, (ii) any possession tax credits

(section 27) and (iii) any credits for testing certain drugs (section 28). Generally, ataxpayer’s “tentative minimum tax” is equal to the minimum tax rate (20 percent in thecase of corporate taxpayers and 26-28 percent in the case of noncorporate taxpayers) ofthe excess of the taxpayer’s alternative minimum taxable income for the taxable yearover the exemption amount. I.R.C. § 55(b)(1).

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may be carried forward (such carryforward being limited only by thetaxpayer’s aggregate regular income tax for such year) and used in futureyears to offset excess regular tax.11

In order to take full advantage of the section 29 credit, an investormust have a strong expectation that such investor will be paying significantamounts of regular tax for the next six years (the credit expires in the year2002).12 In addition, the investor must also expect that the excess of itsregular income tax over its tentative minimum tax will remain adequatelyhigh in order to avoid application of the credit ceiling in any tax year.

Most producers, as a result of intangible drilling cost deductions and/or depletion deductions, are not paying regular federal income tax. Rather,producers commonly pay alternative minimum tax. As a result, producersgenerally are unable to utilize any section 29 credits. In fact, a number ofproducers have a significant amount of credits to carry forward so that ifthey are ever paying regular tax, it will be sheltered for a significant periodof time. Thus, producers often are willing to sell their unused section 29credits (together with the qualifying property) to someone willing to paycash for them.

[3] — Theoretical Risk: Reduction from Phase-outof the Credit.

The section 29 credit is subject to being phased out at certain oilprices.13 The section 29 credit is reduced (possibly to zero) if the averagewellhead price per barrel for all domestic crude oil sales for the year inissue exceeds the phase-out amount.14 Although the credit was fully phasedout when enacted in 1980, there is now little, if any, chance of a phase-out

11 I.R.C. § 53(d)(1)(B)(iii). The credit which has been carried forward may be used inthe first year in which the taxpayer’s regular tax (as adjusted) exceeds the sum of (a) thetentative minimum tax for such year and (b) the section 29 credit earned in such year.Prior to 1987, a taxpayer either used the credit to offset his excess regular tax liability inthe taxable year in which the credit was earned or lost the credit forever.12 See, however, footnote 43, infra (for extension of credit period on certain possibilities).13 I.R.C. § 29(b)(1).14 Section 29(b) provides that the statutory amount of the credit (adjusted for inflation)will be reduced by a fraction (a) the numerator of which is the difference between (i) the“reference price” of oil and (ii) $23.50 (adjusted for inflation), and (b) the denominator

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of the section 29 credit, given that (1) the price at which a phase-outwould occur continues to rise (i.e., it is adjusted for inflation) and (2) theaverage domestic sale price has remained essentially constant for the last8 years. As an illustration, the average wellhead price per barrel for alldomestic crude oil in 1995 was $14.62.15 In contrast, the price at whichthe section 29 credit would begin to phase out was $45.68.16 Moreover,the credit would not have been fully phased out unless the average priceof domestic oil sold for the entire 1995 year had exceeded $57.34.17 Thusthe price of oil would need to triple before the phase-out begins to apply.While unlikely to occur, most prudent investors call for an adjustment inthe portion of the purchase price attributable to the credit value in theevent of a phase-out of the section 29 credit.

[4] — Other Risk in Credit Amount: Reductionsfrom Government Subsidies, Grants, Tax-exemptFinancing, and Other Tax Credits.

Investors should also consider reductions to the credit amount undersections 29(b)(3)-(5). The section 29 credit is reduced if the seller receivedcertain subsidies, grants, or tax-exempt financing in developing theproperty.18 The reductions are proportional in regard to the grants, loans,or financing, relative to the aggregate capital expenditures with respect to

of which is $6.00 (adjusted for inflation). For purposes of this calculation, the referenceprice is the Service’s estimate of the average wellhead price per barrel for all domesticcrude oil, the price of which is not subject to regulation by the United States. See I.R.S.Notice 96-29, supra at footnote 8. To demonstrate how the phase-out of the credit works,

assume that the reference price for 1995 was established at $48.00 and that the credit was$5.83 per barrel equivalent. The credit would be subject to partial reduction in thesecircumstances because the reference price exceeded $45.68 (i.e., $23.50 multiplied bythe inflation adjustment factor of 1.9439). The amount of the reduction would be $1.16per barrel-of-oil equivalent ($.20 per mcf), determined by multiplying the unreducedcredit of $5.83 by a fraction, the numerator of which would be 2.32 ($48.00 minus ($23.50

times 1.9439)), and the denominator of which is 11.66 ($6.00 times 1.9439).15 See I.R.S. Notice 96-29, supra at footnote 8.16 Id.17 Id.18 I.R.C. §§ 29(b)(3), (4), and (5). The Service has issued several rulings which holdthat oil price supports and federal price and loan guarantees are not considered “grants”

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the project.19 The section 29 credit is also reduced if the investor claimingthe section 29 credit is receiving any other energy credits or the enhancedoil recovery credit. The reductions are dollar-for-dollar with regard toany energy tax credit allowed,20 and the aggregate unrecaptured newenhanced oil recovery credit taken.21

In section 29 transactions, investors usually obtain representationsfrom the seller that no subsidies, grants, or tax-exempt financing wereused to develop the property.22 Generally, an investor will accept the risk

for this purpose. See Rev. Rul. 85-77, 1985 C.B. 14 (fuel price support payments paid bythe United States are not grants which reduce the section 29 credit). See also I.R.S.Letter Ruling 8428035 (Apr. 6, 1984)(financial assistance provided by a federalinstrumentality consisting of price guarantees and loan guarantees is not a grant norsubsidized energy financing which would reduce the section 29 credit) and I.R.S. LetterRuling 8410092 (Dec. 7, 1983)(price support payments made by a federal entity will not

be considered “grants” under section 29(b)(3)).19 I.R.C. § 29(b)(3)(A). The amount by which the section 29 credit is reduced pursuantto section 29(b)(3) for any taxable year is determined as of the close of the taxable year.See I.R.C. § 29(b)(3)(B).20 I.R.C. § 29(b)(4). For purposes of the reduction, all energy tax credits allowed to anyparty with respect to the property producing the qualified fuel are taken into account

(subject to reduction by the aggregate amount recaptured with respect to such credits, ifany).21 I.R.C. § 29(b)(5). The amount of reduction with respect to a project, computed on anannual basis for every taxable year beginning after December 31, 1990, is equal to theexcess of (i) the aggregate of enhanced oil recovery credits allowed under section 38 inthat taxable year and in prior taxable years with respect to such project over (ii) the

aggregate of enhanced oil recovery credits recaptured in prior taxable years with respectto such project plus the amount of section 29 credits previously disallowed because ofsuch excesses.22 Illustrative representations regarding these property-level requirements are as follows:no grants have been or will be provided by the United States, a State or political subdivisionof a State “for use in connection with any project” (within the meaning of Section

29(b)(3)(A)(i)(I) of the Code) that includes any of the [assets]. No proceeds of any issue ofState or local government obligation has or will be “used to provide financing for anyproject” (within the meaning of Section 29(b)(3)(A)(i)(II) of the Code) that includes anyof the [assets]. No “subsidized energy financing” (within the meaning of Section 48(a)(4)(C)of the Code) has been or will be “provided in connection with any project” (within themeaning of Section 29(b)(3(A)(i)(III) of the Code) that includes any of the [assets].

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that the other potential reductions could apply, since such reductions arewithin the control of such investor.23

§ 13.03. Representations Regarding Qualifyingthe Property Obtained from the Seller: StatutoryRequirements for Eligibility.

The section 29 credit is earned by selling “qualified fuel” producedfrom wells (or facilities) located in the United States to an unrelated party.24

Although several types of nonconventional fuels are listed in section 29(c),a significant amount of investment has focused primarily on gas from coalseams and tight formations. This section of the chapter will discuss the“property level” or statutory prerequisites for eligibility. The five statutoryproperty-level requirements are as follows: (1) fuel produced must be aqualified fuel, (2) taxpayer claiming credit must be treated as the owner ofthe reserves (i.e., economic interest requirement), (3) well must be drilledduring applicable period (i.e., the drilling requirement), (4) qualifyingproduction was not producible from pre-1980 wells (i.e., the priorproduction limitation), and (5) production must be sold to an unrelatedbuyer (i .e., the sale requirement). In each subsection, a style ofrepresentation typically given by the seller to the buyer with respect to theapplicable statutory requirement will be included.

[1] — Source of the Production: Qualified Fuel Requirement.Generally, four types of fuels may qualify for the credit:

(i) oil produced from shale and tar sands;25

23 An investor could require the seller, if acting as operator, to make the followingrepresentation: no energy credit or enhanced oil recovery credit has been or will be takenwith respect to any project in which the [assets] are included.24 I.R.C. § 29(d)(1). The term “United States” in this context includes the seabed andsubsoil of the territorial waters of the United States and any possessions of the UnitedStates. Some investors, in order to assure compliance with this requirement, obtain the

following representation from the seller: All production from the Properties will be fromwells located within the United States (in accordance with Section 29(d)(1)(A) of theCode). Requiring the seller to make this representation seems a bit excessive to thisauthor. One might expect that due diligence would confirm this requirement.25 The legislative history defines oil produced from shale as “the liquid oil obtainedfrom shale rock after the retorting (heating) process).” See 1979 Senate Report, supra at

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(ii) gas produced from geopressured brine, Devonian shale, coal seams,or a tight formation;26

(iii) gas produced from biomass27 (defined as any organic materialother than oil, natural gas, coal, or any product thereof); and

(iv) synthetic fuels produced from coal (whether liquid, gaseous orsolid).28

p. 88. However, neither the statutory provisions of section 29 nor the legislative reportsspecifically address the definition of oil produced from tar sands. In 1989, the Service

issued a technical advice memorandum in which oil from tar sands was defined as “anextremely viscous hydrocarbon which is not recoverable in its natural state by conventionaloil well production methods including currently used enhanced recovery techniques.”See I.R.S. Letter Ruling 8940004 (June 20, 1989)(adopting the definition of tar sands setforth in Federal Energy Administration Ruling 1976-4, 41 Fed. Reg. 25,886 (1976)). In1993, the Tax Court held that Congress intended the FEA definition of tar sands would

be utilized in determining the type of oil qualifying for the section 29 credit. See TexacoInc. v. Commissioner, 101 T.C. No. 38 (Dec. 15, 1993).26 Section 29(c)(2)(B) contains a special limit on the classification of gas producedfrom a tight formation as a qualified fuel. Gas produced from a tight formation after1989 will be classified as a qualified fuel only if such gas (i) was, as of April 20, 1977,committed or dedicated to interstate commerce in accordance with section 2(18) of the

NGPA, or (ii) is produced from a well drilled after November 5, 1990. Prior to the 1990amendment, gas produced from a tight formation (other than gas which was dedicated tointerstate commerce) was classified as a qualified fuel only if (i) the price of such gaswas regulated and (ii) the maximum lawful price for such gas under the NGPA was atleast 150 percent of the then applicable price under section 103 of the NGPA.27 See I.R.S. Letter Ruling 9529019 (April 24, 1995). Also, the Service has ruled

privately that the sale of steam produced from biomass (rather than gas produced frombiomass) to an unrelated third party entitled the seller of the steam to take the section 29credit with respect to the biomass. I.R.S. Letter Ruling 9044043 (Aug. 3, 1990). Because

gas was not actually being sold, the Service ruled further that in order to calculate theproper amount of the section 29 credit the taxpayer should determine the hypotheticalBtu content of a hypothetical gas stream based upon the Btu content of the steam injectedinto the third party’s boiler. c.f. I.R.S. Letter Ruling 9320017 (Feb. 18, 1993).28 See I.R.S. Letter Ruling 9611013 (December 11, 1995); I.R.S. Letter Ruling 9549025

(September 8, 1995); I.R.S. Letter Ruling 9526006 (March 17, 1995); I.R.S. Letter Ruling9525005 (March 17, 1995); I.R.S. Letter Ruling 9524013 (March 17, 1995); and I.R.S.

Letter Ruling 9524012 (March 17, 1995). The Service has ruled that certain processeswill be treated as creating synthetic fuels. See Rev. Rul. 86-100, 1986-2 C.B. 3 (synthetic

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Typically, the seller is responsible for confirming and substantiatingthat the hydrocarbons purchased by the investor are a “qualified fuel.”29

With respect to oil from tar sands and shale, synthetic coal, and biomass,one can prove that a fuel is a qualified fuel using whatever information isavailable. With respect to all gas qualifying for the section 29 credit, thestatute contemplates that a certification would be obtained confirming thesource of production from the state jurisdictional agency and the FederalEnergy Regulatory Commission (FERC).30 Also, state jurisdictional

fuel produced from processing coal will be treated as a qualified fuel because the newsynthetic product differs significantly in chemical composition, as opposed to physicalcomposition, from the feedstock used to produce the synthetic fuel). Several previouslyissued letter rulings as to what qualifies under section 29(c)(1)(C) were recently revokedby the Service. See e.g. I.R.S. Letter Ruling 9519013 (February 14, 1995) reconsideringI.R.S. Letter Ruling 8805043); I.R.S. Letter Ruling 9519051 (February 14,1995)(reconsidering I.R.S. Letter Ruling 8635021); I.R.S. Letter Ruling 9521013(February 28, 1995)(reconsidering PLR 9412025).29 In the 1990 Act, Congress eliminated the requirement that the price of the gas mustbe regulated in defining eligible “gas from a tight formation” after December 31, 1990.I.R.C. § 29(c)(2)(B). Under the statutory amendment, gas produced from a tight formation(which was not committed or dedicated to interstate commerce as of April 20, 1977) willqualify for the credit if such gas is produced from a well drilled after November 5, 1990,the enactment date of the 1990 Act. See also I.R.S. Letter Ruling 9127054 (Apr. 11,1991). Gas which was committed or dedicated to interstate commerce as of April 20,1977, will continue to qualify for the section 29 credit, even if deregulated. I.R.C. §29(c)(2)(B)(i). To the extent applicable, the following representation should be obtainedby an investor from the seller:

Each tight formation gas well, the gas from which was committed or dedicatedto interstate commerce as of April 20, 1977, included in the Properties wasdrilled (within the meaning of Section 29(f) of the Code) after December 31,1979, and before January 1, 1993. All other tight formation gas wells includedin the Properties were drilled, within the meaning of Section 29(f) of the Code,after November 5, 1990, and before January 1, 1993.

30 See I.R.C. § 29(c)(2)(A). This section provides specifically that the determination asto whether gas is produced from geopressure brine, Devonian shale, coal seams or atight formation must be made in accordance with section 503 of the Natural Gas PolicyAct of 1978 (the NGPA). However, the Service has ruled privately that a taxpayer is notrequired to obtain the certification under section 503 of the NGPA prior to the time thetaxpayer takes the section 29 credit on his return. See I.R.S. Letter Ruling 8848001(Dec. 2, 1988).

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agencies quit issuing (or accepting applications for) certifications necessaryunder the NGPA to obtain FERC approval. Thus, if certification had notbeen obtained, it became impossible to get the required certification. As aresult certifications cannot currently can be obtained regarding certaingas wells which were drilled within the applicable time limits and producedfrom a qualifying zone.

The lack of certification raises concerns that a statutory prerequisitehas not been met. To date, the Service, while apparently aware of theproblems, has not issued any guidance. Generally, sellers are taking theposition that these wells should qualify for the section 29 credit becausethe sole reason the certification has not been obtained in the disbandingof the FERC. Otherwise, the wells meet all requirements for certification.Hopefully, the Service will provide guidance on this issue in the nearfuture.31

[2] — Ownership Requirement.The section 29 credit is available only to a taxpayer who holds an

ownership interest in the property from which the qualified fuel isproduced.32 The applicable legislative history provides that with respectto (a) oil produced from shale and tar sands and (b) gas produced fromgeopressure brine, Devonian shale, or coal seams the credit would be

31 In most transactions involving gas qualifying for section 29, the seller has obtained

certifications on all wells in issue, and is willing to make the following representation:All non-liquid gas produced from the [describe wells and producing horizon] has been[or will be] determined in accordance with Section 503 of the NGPA to be productionfrom coal seams, Devonian shale, or tight formations to the extent required under Section29(c)(2)(A) of the Code. By altering the bold language, the seller can take the risk (andone would expect, receive payment for the credit value) on any gas well currently lacking

a certification.32 I.R.C. § 29(a)(2)(B)(stating that the “production” of the qualified fuel must be“attributable to the taxpayer.”) See also I.R.C. § 29(d)(3). In Revenue Ruling 93-46,1993-2 C.B. 3, the Service held that the owner of a royalty interest is entitled to receivean allocable portion of the section 29 credit based on such owner’s share of gross proceedsfrom the sale of the qualified production. Likewise, in Revenue Ruling 94-48, 1994-2

C.B. 3, the Service concluded that the holder of a net profits interest was entitled to thesection 29 credit on such holder’s net share of gross sales.

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based on the taxpayer’s economic interest in the property (within themeaning of section 613(a)).33 However, there apparently is no requirementthat the owner of the section 29 property be “at risk” with respect to hisinvestment in the property in order to receive the tax credit.34

The section 29 credit is not allocated to a person who receives revenuefrom the sale of the qualified fuel in repayment of a debt. Thus, the holderof a production payment treated as debt under section 636 is not entitledto the section 29 credit.35 Likewise, to the extent that a bank receivesproduction proceeds in repayment of a nonrecourse debt, the credit isallocated to the “equity” owner and not to the bank in its capacity aslender. Although a property may be burdened by a production payment,100 percent of the section 29 tax credits on production used to service thedebt will flow to the holders of the economic interest with respect to suchproperty in proportion to their respective shares of such debt. As a result,as explained below, the proceeds from the sale of production can remainwith the seller under a production payment while the tax credits attributableto revenue received by both the burdened interest and the productionpayment flow exclusively to the holder of the burdened interest.36

[3] — Sharing Credits Among Investors: ApportioningSection 29 Credits Among Holders of EconomicInterests.

The section 29 credit is apportioned between holders of economicinterests in a qualifying property based on the amount of productionattributable to each such holder.37 Section 29(d)(3) provides generallythat production from the property or facility must be allocated among allof the persons owning an interest (economic or equity, respectively) insuch property or facility in proportion to their respective shares in the

33 See 1979 Senate Report at p. 88.34 See I.R.S. Letter Ruling 9126016 (Mar. 29, 1991), concluding that the section 29

credit “should be available to investors who are not at risk within the meaning of section465 with respect to the activity generating the credit.”35 I.R.C. § 636.36 See discussion at footnotes 72 through 90 and accompanying text.37 I.R.C. §29(a)(2)(B).

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gross sales from such property or facility (i.e., their respective shares ofthe gross revenue from the sale of the qualified fuel).38

If a partnership owns an interest in a property or facility, the section29 credit attributable to such interest will be further apportioned amongits partners.39 The direct allocation of a tax credit among partners of apartnership, however, cannot qualify for one of the safe harbor allocationscontained in the section 704 regulations because such regulations expresslyprovide that the allocation of any tax credit cannot have “economiceffect.”40 In the absence of a safe harbor, practitioners must turn to theprinciples underlying the regulations to determine whether the proposedmanner of allocating the section 29 credit will be sustained. Under section704(b) principles, a partner’s share of the section 29 credit would bedetermined on the basis of his or her interest in partnership income derivedfrom the partnership’s gross revenue from the sale of the qualified fuel.41

Accordingly, tax credits (including the section 29 credit) must be shared

38 I.R.C. § 29(d)(3). For example, assume that four people owned an interest in a propertyproducing a qualified fuel: (1) A holds a 12.5 percent royalty interest, (2) B holds anoverriding royalty interest equal to 10 percent of 8/8ths which burdens only the workinginterest, (3) C holds a 30 percent net profits interest which burdens only the workinginterest (for purposes of this example, expenses are assumed to be equal to 25 percent of

the gross proceeds after payment of the aggregate royalty burdens), and (4) D holds theentire working interest. If 12,000 Mcf of coalbed methane gas is produced from theproperty and sold in 1995 with a credit of $1.00 per Mcf, the credit would be apportionedas follows: (i) A would receive $1,500 of credit (12.5 percent of 12,000 multiplied by$1.00), (ii) B would receive $1,200 of credit (10 percent of 12,000 multiplied by $1.00),(iii) C would receive $2,092 of credit ((30 percent of 75 percent (assumed net profits

after expenses) of D’s 77.5 percent net revenue interest) times $1.00)), and (iv) D wouldreceive the remaining $7,208 of credit.39 I.R.C. §§ 7701(a)(1)-(2) and (14). See in accord I.R.S. Letter Ruling 8738085 (June29, 1987) and I.R.S. Letter Rulings 8422132, 8422134 and 8422137 (all issued on Feb.29, 1984).40 Treas. Reg. §1.704-1(b)(4)(ii).41 Treas. Reg. § 1.704-1(b)(4)(ii) provides that although the allocation of tax creditscannot satisfy the safe harbor set forth in the regulations, if a partnership receipt thatgives rise to a tax credit also gives rise to a valid allocation of partnership revenue (whichis reflected in the partners’ capital accounts), then the partners’ share of the tax creditshall be in the same proportion as the partners’ respective shares of such revenue.

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by the partners in accordance with their respective shares of gross revenuefrom the sale of the qualified fuel giving rise to the section 29 credit.42 Ifthere is a change in a partner’s interest in the partnership during the taxableyear, the section 29 credit allocated to each partner will be determined onthe basis of such partner’s interest in the partnership at the time the qualifiedfuel is sold.43

[4] — Drilling Requirement.The section 29 credit is available only if production is from (i) a well

drilled after December 31, 1979, and before January 1, 1993 (referred toas the “new well requirement”), or (ii) a facility placed in service afterDecember 31, 1979, and before January 1, 1993.44 The terms “well” and“drilled” are not defined in the statutory provisions or the attendantcommittee reports.45 The Service has issued a public ruling concludingthat a well is “drilled” for purposes of section 29 when the well is spudded,provided that drilling is continuous to the productive horizon.46

42 See Treas. Reg. §§ 1.704-1(b)(4)(ii) and 1.704-1(b)(3). See also I.R.S. Letter Ruling8942068 (July 26, 1989)(holding that each person who owns an interest in the partnershipat the time the qualified fuel is sold will receive an allocation of the section 29 credit withrespect to its share of the income attributable to the sale of the qualified fuel, regardless

of whether the taxpayer owned its interest in the partnership at the time the qualified fuelwas produced).43 I.R.C. § 706.44 I.R.C. § 29(f)(1). Section 29(g) modifies Code Section 29(f) to extend until January 1,1997, the time within which certain facilities must be placed in service to qualify for thesection 29 credit. I.R.C. § 29(g)(1)(A). For qualified fuels produced from such facilities,

the credit period has been extended until December 31, 2007. I.R.C. § 29(g)(1)(B). The1990 Act extended by two years the time within which a well must be drilled in order toenable the production from the well to qualify for the section 29 credit.45 The term “facilities placed in service” is also not defined in the Code or the applicablecommittee reports. See, however, I.R.S. Letter Ruling 9529019 (April 24, 1995).46 Rev. Rul. 90-70, 1990-2 C.B. 3. In this ruling, the Service defined the “spudding” of

a well as the “initial boring of the hole.” Id. Thus, a well will satisfy the new wellrequirement if the initial boring of the hole was begun during the qualifying period. See

also I.R.S. Letter Rulings 8848015 (Aug. 30, 1988) and 8915019 (Jan. 10, 1989). TheService explained in Rev. Rul. 90-70 that drilling would be considered continuous even

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Any current recompletions and completions from sideways extensions(“directional drilling completions”) from wells bored prior to 1980 whichare effected after December 31, 1979, and before January 1, 1993, satisfythis definition of the term “drilled.”47 The Service has confirmed this in apublished ruling emphasizing only that the recompletion must be uphole(reasoning that the well qualifies because it was drilled through thequalifying horizon before January 1, 1993 even though production hadnot begun).48

The Service has not issued direct guidance as to the definition of theterm “well” for purposes of section 29. The Service has acknowledged inprivate rulings, however, that gas produced from vertical ventilation shafts

if delays occur, provided that the delays are due to factors “beyond the taxpayer’s control,”such as mechanical repairs, severe weather conditions, and operation of federal and state

laws. See also I.R.S. Letter Ruling 8915019 (Apr. 14, 1989)(suspension of drilling becauseof strikes, inclement weather, retrieving lost tools in the hole, etc. not fatal to availabilityof section 29 credit) and I.R.S. Letter Ruling 9316033 (Jan. 26, 1993)(delay of over 12months to develop alternative stimulation techniques was permissible).47 See I.R.S. Letter Rulings 9117033 (Jan. 25, 1991), 9111008 (Dec. 7, 1990), 9025007(Mar. 19, 1990), 9025002 (Mar. 2, 1990), and 9025003 (Mar. 12, 1990). In these rulings,

the pre-1980 wellbores had been drilled for the production of conventional gas fromdeeper deposits and had not been drilled with the expectation of producing coal seamgas. After 1979 and before 1991, the taxpayer recompleted the wells and drilled wellsthrough directional drilling completions from old wellbores for the purpose of producingcoal seam gas. The Service determined that a recompletion or directional drillingcompletion connotes “the establishment of a new conduit which grants the access to and

allows the withdrawal of the mineral resource.” The Service further stated that arecompletion includes “the installation of a new conduit or new flow line between apreviously untapped coal seam gas deposit” and the surface. Based on these definitions,the Service concluded that the coal seam gas produced from recompletions or directionaldrilling completions in these pre-1980 wellbores would satisfy the new well requirement.See in accord, I.R.S. Letter Ruling 9027005 (Mar. 26, 1990)(ruling that the recompletion

of wells and the directional drilling completion of pre-1980 wells “effect[ed] the intendedeconomic tapping of new reserves” by granting access to and allowing the withdrawal ofthe coal seam gas).48 Rev. Rul. 93-54, 1993-27 I.R.B. 4. This ruling also holds that a recompletion whichdeepens a well drilled within the qualifying period will not satisfy the drilling requirementof section 29(c) because such well was not drilled to the qualifying horizon until after

January 1, 1993.

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and underground horizontal conduits will qualify for the section 29credit.49 A vertical ventilation shaft is a shaft drilled from the surface intothe coal seam primarily to allow the methane gas to be removed prior tothe actual mining of the coal. In addition to the vertical ventilation shafts(which are commonly referred to as “vent holes”), the coal operator usuallydrills horizontal shafts into the coal bed and then uses polyethylene pipeto connect those shafts to the vertical conduits which allow additionalmethane gas from the coal bed to be removed prior to the mine through ofthe coal. These horizontal shafts are often referred to as “short holes.”50

[5] — Prior Production Limitation.The section 29 credit is available only if no gas had been produced on

the property from Devonian shale, coal seams, geopressure brine, or atight formation prior to January 1, 1980.51 This limitation applies only tothe credit on gas produced from Devonian shale, coal seams, geopressurebrine, or a tight formation.52 The term “property” is not defined in section29 for this purpose, and the legislative history is ambiguous. Likewise,the NGPA does not contain a definition of the term “property.”

In responding to private inquiries, the Service has issued several privaterulings which define the term property as a proration unit.53 Under this

49 See I.R.S. Letter Ruling 9044073 (Aug. 8, 1990).50 Id. See also I.R.S. Letter Ruling 9050024 (Sept. 14, 1990)(concluding that gasproduced from the coal bed through vertical ventilation shaft will qualify for the credit ifsuch shafts are drilled during the drilling period (which currently ends on December 31,1992)).51 I.R.C. § 29(d)(4).52 When the period for drilling a new well was extended in 1988, the attendant conferencecommittee report added a clarification that the prior production limitation would onlydisqualify a fuel if the same type of fuel had been produced from the property prior to1980. See H.R. Rep. No. 1104, 100th Cong., 2d Sess. p. 244 (1988). The limitation willnot apply where a fuel of a different type from a different geological formation is produced.53 See I.R.S. Letter Rulings 9351021 (Sept. 27, 1993), 9327061 (Apr. 9, 1993), 9044036

(Aug. 2, 1990), and 8950026 (Sept. 18, 1989). At present, for ruling purposes, the Servicehas adopted the definition of proration unit set forth in the NGPA (and in these privaterulings) as follows:

(i) Any portion of a reservoir, as designated by the State or Federalagency . . ., which will be effectively and efficiently drained by a single

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definition, a property will not be disqualified as a result of the priorproduction limitation unless there was production from the same prorationunit prior to 1980. Thus, a qualifying well drilled on leasehold acreageheld by production from pre-1980 wells, which pre-1980 wells hadpenetrated and produced from the qualifying formation, should not causesuch new well to fail to qualify for the section 29 tax credit by reason ofapplication of the prior production limitation.54

[6] — Sale Requirement.A taxpayer is eligible to take the credit during the year in which the

qualified fuel is sold.55 The credit may only be earned on sales throughDecember 31, 2002.56 In order to be eligible to take the credit in the yearof sale, the taxpayer must sell the qualified fuel to an “unrelated” buyer

well; (ii) Any drilling unit, production unit or comparable arrangement

designated or recognized by the State or Federal agency . . ., to describethat portion of such reservoir which will be effectively and efficientlydrained by a single well; or (iii) If such portion of a reservoir, unit orcomparable arrangement is not specifically provided for by State law orby any action of any State or Federal agency . . ., any voluntary unitagreement or other comparable arrangement applied, under local custom

or practice within the locale in which such reservoir is situated, for thepurpose of describing the portion of a reservoir which may be effectivelyand efficiently drained by a single well. See 15 U.S.C. § 3301(8).

For a discussion of the effect of downspacing proration units, see I.R.S. Letter Ruling9248035 (September 2, 1992) and I.R.S. Letter Ruling 9224014 (May 10, 1992).54 Sellers often give the following representation to buyers: No portion of the [describe

qualifying production] is or will be treated as attributable to a property from which[name qualified fuel: coal seam, Devonian shale, or tight formation gas] was producedin marketable quantities before January 1, 1980, within the meaning of Section 29(d)(4)of the Code.55 I.R.C. § 29(a)(2)(A). The section 29 credit may be earned and taken by a taxpayerwho sells his production on or before December 31, 2002.56 I.R.C. §29(f)(2). The Service has ruled privately that a cash basis taxpayer is entitledto take the section 29 credit in the taxable year in which the taxpayer recognizes incomefrom the sale of the qualified fuel, even though the transfer of title and change of possessionmay have taken place in the previous taxable year. See I.R.S. Letter Ruling 8532016(May 6, 1985).

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without receiving incentive pricing.57 For this purpose, two persons willbe treated as related if such persons would be treated as a single employerunder the common control test set forth in section 52(b) of the Code.58

With respect to a partnership, the sale of a qualified fuel to a partnershipby a 50 percent or less partner should be treated as a sale to an unrelatedperson.59 Likewise, the sale of a qualified fuel to a 50 percent partner bya partnership should also be treated as a sale to an unrelated person.60

Finally, the sale of a qualified fuel to a 100 percent affiliate is ignored ifthe affiliate ultimately sells the qualifying fuel to an unrelated person.61

57 A taxpayer may not claim both (i) an incentive price determined under section 107 ofthe NGPA and (ii) the tax credit under section 29. See I.R.C. § 29(e)(1). Nevertheless theService has recognized that a taxpayer could receive an incentive price in one month (butforego the credit) and the tax credit in a different month (but forego the incentive price).See Rev. Rul. 86-2, 1986-1 C.B. 3. See also I.R.S. Letter Rulings 8829066 (Apr. 27,1988) and 8422132 (Feb. 29, 1984).58 The regulations under section 52 make special provisions for a parent-subsidiarygroup, a brother-sister group and a combination thereof in determining whether trades orbusinesses are under common control. See Treas. Regs. §§ 1.52-1(b)-(e). A parent-subsidiary group is considered to be under common control if it consists of one or morechains of organizations conducting trades or businesses, in each of which a controllinginterest (more than 50 percent) is owned by one or more of the organizations. A brother-

sister group is considered to be under common control if two or more organizationsconducting trades or businesses are owned by the same five or fewer persons who areindividuals, estates or trusts, and these persons (singular or in combination) own acontrolling interest (at least 80 percent) in each organization. A combined group isconsidered to be under common control if a group of three or more organizations has (a)each organization as a member of either a parent-subsidiary group under common control

or a brother-sister group under common control and (b) at least one or more organizationsis the common parent organization of a parent-subsidiary group under common controland is a member of a brother-sister group under common control.59 See I.R.S. Letter Ruling 8833044 (May 26, 1988). See in accord I.R.S. Letter Ruling9039016 (June 28, 1990)(sale of qualified fuel between two partnerships with a commonpartner is treated as a sale to an unrelated buyer).60 See I.R.S. Letter Ruling 8738085 (June 29, 1987).61 See I.R.S. Letter Ruling 9322010 (Mar. 5, 1993).

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§ 13.04. Passive Activity Limitations.A noncorporate taxpayer’s ability to take advantage of the tax benefits

of the section 29 credit must be evaluated in light of the potentialapplication of the passive activity limitations. The passive loss limitations,which were enacted in 1986, prohibit a taxpayer from using losses or taxcredits derived from passive activities to offset nonpassive income orreduce the regular tax attributable thereto.62 Thus, a noncorporate taxpayerwill not be entitled to reduce his regular tax on active income if the section29 credit is derived from oil and gas activities which are treated as passiveactivities. Generally, the passive activity limitations do not apply tosubchapter C corporations other than personal service corporations andclosely held corporations.63

A passive activity is defined generally as an activity which involvesthe conduct of any trade or business in which the taxpayer does notmaterially participate.64 To understand the application of the passiveactivity rules in the context of oil and gas operations, a taxpayer must firstdetermine his oil and gas operations will constitute a single activity because(a) tax credits derived from a single activity can be used to reduce theregular tax attributable to (i) such activity and (ii) similarly classifiedactivities, and (b) the applicability of the passive activity limitations isdetermined on an activity-by-activity basis.65 A taxpayer must determinewhether his oil and gas activity constitutes a “trade or business.”66 Underthe passive activity regulations, if held for investment, a taxpayer owninga royalty interest, an overriding royalty interest, or a net profits interestshould not be treated as conducting a trade or business.67 If holding suchinterests for investment does not constitute a trade or business, then the

62 I.R.C. § 469.63 I.R.C. § 469(a)(2). See Temp. Treas. Regs. §§1.469-1T(g)(1)-(2).64 I.R.C. § 469(c)(1). See Temp. Treas. Reg. § 1.469-1T(e)(1)(ii). See Temp. Treas.Regs. §§ 1.469-1T(g)(1)-(2).65 See Treas. Reg. § 1.469-4. Second, because the passive activity limitations areapplicable only to activities which constitute a “trade or business,”I.R.C. § 469(c)(1)(A).66 See Treas. Regs. §§ 1.469-1(e)(2) and 1.469-4(b)(1).67 See Rev. Rul. 73-428, 1973-2 C.B. 303 (treating a royalty interest as a capital asset if

held for investment but as an ordinary asset if held primarily for sale to customers in theconduct of a trade or business).

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income and credits derived from such activities should not be subject tothe passive activity limitations.68 Conversely, a taxpayer owning a workinginterest will be considered to be in a trade or business and the income andtax credit derived from such interest would be passive or active dependingon whether the taxpayer materially participates in the activity.69 Finally,after determining that certain groups of wells will be treated as a separateactivity and that the activity constitutes a trade or business, a taxpayermust then determine whether he has materially participated in suchactivity.70 A taxpayer should structure his activities to cause the section29 credit to be classified as either passive or active, depending on suchtaxpayer’s individual tax circumstances.

§ 13.05. Pay-As-You-Go Structures; Leveraged Acquisitionsof Section 29 Properties.

Owners of qualifying properties often find themselves unable to usethe credits because of inadequate regular taxable income or alternativeminimum taxes in excess of regular tax.71 Such owners may find itadvantageous to transfer interests in qualifying properties to persons whoare able to use the credit in exchange for a purchase price or otherconsideration that takes into account the value of the credits to thetransferee.

The Service has published six rulings (at the time of this chapter)addressing various issues arising in a “pay-as-you-go” structure.72 Thisstructure derives its name from the deferred portion of the purchase priceattributable to the credit value. Under the “pay-as-you-go” arrangement,the buyer makes quarterly payments of an agreed percentage of the credit

68 See Temp. Treas. Reg. § 1.469-3T(b)(1)(i)(A).69 See Temp. Treas. Reg. § 1.469-1T(e)(4)(iv).70 A taxpayer is considered as materially participating in an activity if he meets one of

seven tests provided in Temp. Treas. Reg. § 1.469-5T. See also I.R.C. §§ 469(c)(3)-(4).71 See discussion at footnotes 11 to 12 supra and accompanying text.72 I.R.S. Letter Ruling 9622024 (February 29, 1996); I.R.S. Letter Ruling 9615017(December 27, 1995); I.R.S. Letter Ruling 9610011 (December 5, 1995); I.R.S. LetterRuling 9601034 (October 3, 1995); I.R.S. Letter Ruling 9473006 (June 10, 1994); and

I.R.S. Letter Ruling 9414021 (January 6, 1994).

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amount each quarter, based on the actual production volumes for suchquarter. To the extent the production is reduced, the credit payments forsuch quarter are correspondingly reduced. Conversely, to the extentproduction exceeds expectations, the contingent purchase price attributableto the credit value is increased.

As previously discussed, the purchase price paid by the buyer iscomposed of two elements, the hydrocarbon value and the credit value.73

The hydrocarbon value, based on the buyer’s anticipated share of the netcash proceeds from sale of the hydrocarbons, is typically paid in a lumpsum at closing (i.e., an up-front cash payment). The credit value, basedon the buyer’s share of the tax credits arising from the sale of hydrocarbonsactually produced, is paid quarterly pursuant to a recourse note as thecredits are earned, and expires at the end of the credit period.

As part of the transfer, the seller retains the lion’s share of the economicupside by keeping both (1) a production payment74and (2) a contingentreversionary interest. The Service has ruled privately that the tax crediton the entire economic interest shifts to the buyer at closing, even thoughthe seller has retained a substantial portion of the economic (non-tax)benefits arising from ownership of the section 29 property.75 Eachcomponent of the compensation received and/or retained by the seller ina pay-as-you-go structure is discussed in detail below.

73 See discussion at footnotes 8-10, supra and accompanying text.74 By retaining an interest in the cash flow from the property, the seller increases theattractiveness of the transaction to the investor because the production payment burdenreduces the purchase price the investor must pay for the hydrocarbon value of the acquiredproperty. The reduced purchase price also enhances the after tax rate of return of theinvestor. For example, if the seller disposed of 100 percent of the working interest whileretaining an 80 percent production payment, he would have retained half of the futurecash flow from the property until his interest in the property terminated under the termsof his production payment. In addition, he would receive cash from the disposition of hisworking interest. However because he has retained only a production payment, he wouldnot be entitled to any part of the section 29 credit. The buyer would receive 100 percentof the section 29 credit from the sale of production attributable to the working interestand 20 percent of the cash flow from such sale until the production payment terminates.After the termination of the production payment, the buyer would receive 100 percent of

both the section 29 credit and the cash flow from the sale of the qualified fuel.75 See footnote 74, supra.

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• Cash Down Payment.The portion of the purchase price attributable to the anticipated

revenues from the investor’s share of hydrocarbons is paid in cash at thetime of closing. This portion of the hydrocarbon stream is often referredto as the property’s “tail” in that the investor begins to receive revenue (inlarge part) only after the expiration of the production payment. Thus therevenue received by the investor represents the end or tail of the economiclife of the producing property.

The recently issued private letter rulings indicate that the investor mustpurchase a tail which has an estimated present value after the productionpayment ends of greater than five percent of the present value of the entireproduction stream from the subject interest.76 For purposes of making thiscalculation, the Service is rumored to require SEC-10 pricing be used.77

The use of this pricing establishes the point in the economic life of theproperty at which the production payment must terminate. However, itshould be noted that this pricing does not necessarily establish the value ofthe “tail.” To the contrary, the value of the tail could be negotiated betweenthe parties at whatever pricing expectations the parties have at the time ofclosing. The only cautionary note is that the estimates of property valuesmust have some defensible basis. Putting too high of a premium or discounton the value of the tail for purposes of fixing the cash payment amountmay call into question the form of the transaction.

• Retained Production Payment.As discussed above, the termination date of a production payment

must occur while there remains at least five percent by value of theanticipated production stream at the time the production payment iscreated. The termination of the production payment, however, can bepredicated on (1) the receipt of a fixed volume of gas, (2) the receipt of a

76 See e.g. I.R.S. Letter Ruling 9601034 (at the time the production payment was created,the estimated present value of production remaining after termination of productionpayment was greater than five percent of the present value of the entire expected

production from the section 29 property.77 Regulation S-4, 17 C.F.R. Part 210, Rule 4-10; see also Statement of Financial

Accounting Standards No. 69.

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fixed dollar amount, or (3) the occurrence of a date certain.78 Typically,in pay-as-you-go transactions, the production payment takes 100 percentof the net profits from the subject interest until its expiration.79

The production payment retained in a pay-as-you-go structure mustsatisfy the requirements of Section 636. The section 636 regulationsprovide that the expected duration of the production payment (at the timeof its creation) must be less than the economic life of the property burdenedthereby.80 These regulations provide further that the proceeds received inconnection with the production payment must be limited to the revenuefrom the property.81 In certain circumstances, the parties have agreed topay a portion of the production payment with other than revenue from theproperty. In such event, the production payment would, in all likelihood,be treated as debt rather than a production payment. While, thischaracterization may impact the accounting to both the buyer and theseller, the holder of the debt does not receive any section 29 credits. Suchcredits remain with the borrower.

• Additional Contingent Consideration —Recourse Note.

In the pay-as-you-go structure, the credit value is paid pursuant to arecourse note. The recourse note calls for payments equal to a fixedpercentage of the value of the section 29 credits generated by the actualproduction (based on actual MMBtus sold) from the property for the

78 I.R.C. § 636; Treas. Reg. § 1.636-3(a)(1). For an excellent discussion of variouscomponents of a production payment, see Hardie, “A Reexamination of the DefinitionalElements of Production Payments,” 38 Inst. on Oil & Gas L. & Tax’n. 14-1 (SW Legal

Found. 1987).79 The private letter rulings do not indicate the production payment’s percentage ofrevenue and therefore no comfort can be gained as to the acceptable level of net profits

acceptable to the Service.80 Treas. Reg. § 1.636-3(a)(1). The economic life of a production payment has a shorterduration than the burdened economic interest only if such payment “may not reasonablybe expected to extend in substantial amounts over the entire productive life of such

mineral property.” Id.81 Id. A production payment can not be able to be satisfied by other than production

from the burdened property.

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previous quarter. While the percentage of the credit remains fixed, thepayments typically are adjusted to take into account actual adjustmentsto the amount of the credit.82 As a result, the investor and sellerproportionally share the benefit from adjustments for inflation.

The key requirement is that the obligation to make the credit paymentsbe treated as debt rather than an economic interest in the property. Inorder to ensure this treatment, the note usually calls for full recourse againstthe assets of the investor. Also, the note payments terminate at theexpiration of the credit period on December 31, 2002. The letter rulingshave indicated that a recourse note structured in this manner will be treatedas a debt rather than a royalty interest. Alternatively, to the extentrecoverable only from production from the property, the obligation couldbe treated as a production payment in that it will terminate at the time thecredit expires. In all likelihood, an expiration date in the year 2002 willbe significantly shorter than the economic duration of the subject interest.

The investor may ask for protection from the obligation to make futurenote payments in the event that either (i) the credit is phased out or (ii) thestatute of section 29 (or related provisions) is amended. The phase outand change in law protections are typically incorporated into the recoursenote. The recourse obligation is reduced if either of the events occur.However, the issue of reduction in the contingent note payments is thesubject of negotiation between the parties in any individual transaction.

• Retained Contingent Reversion.In addition to the receipt of the cash payment and the recourse note

and the retention of a production payment, the seller also retains acontingent reversionary interest. This interest springs up when 100 percentof the reserves estimated in the reserve report at closing have beenproduced. Typically, contingent reversion commands a high percentage(approximately 90 percent) of the reserves in excess of the estimatedreserves at closing. Because there is no economic value associated withthese reserves, the existence of a reversionary interest does not undercutthe investor’s ability to claim the ownership of the working interest and,

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82 To the extent the credits are adjusted for inflation, the contingent payments are

likewise adjusted upward.


410

therefore, the section 29 credits. However, this arrangement puts a greatdeal of pressure on the accuracy of the reserve report. To the extent thatthe reserve report improperly underestimates reserves, the Service maychallenge the arrangement stating that the ownership of the investor wasin fact a production payment (to which no credits would pass) because itexpired (or 90 percent of it expired) before the expected economic durationof the property. As a result, the seller would have retained ownership of90 percent of the property and therefore would be allocated acommensurate share of the section 29 credits.

Also, the seller may not be interested in accepting a contingentrevisionary interest in all circumstances. In the event that the productionfrom the property is essentially equal to the expected reserve estimates atclosing, the obligation to take over the property under the contingentreversionary interest would carry with it any plugging and abandoningobligations. These obligations could be substantial and would ariseessentially at the time the reversionary interest springs into existence.Thus, in certain instances, the seller may want the option of rejecting thisreversionary interest if and when it were to arise.

• Purchase Option.Another key component in a pay-as-you-go structure is the seller’s

ability to reacquire the property at the end of the credit period. Typically,sellers are reluctant to remove reserves from their books. However, theService has acquiesced in permitting sellers to keep an option to reacquirethe properties. The critical issue in providing for the terms of a purchaseoption is to give the option price the requisite flexibility to approximatefair market value at the time of its exercise. The three key componentsfrom the Service’s perspective in any formula-based fair market optionare as follows: (1) a new determination of the amount of reserves at thetime the option is exercised; (2) the use of then current pricing at the timethe option is exercised; and (3) an appropriate discount rate at the timethe option is exercised.83 The letter rulings have indicated that if such an

83 In I.R.S. Letter Ruling 9615017, the Service acquiesced in a discount rate derivedfrom the six month London Interbank Offered Rate in effect on the option exercise date

(plus an undisclosed adjustment).

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option is utilized, the existence of the option will not undercut the investor’sability to assert that it is the true owner of the economic interest until theoption is exercised.

• Management or Operating Agreement.Typically, the investor does not desire to actively participate in the

day-to-day operation of the property.84 To accommodate this, buyers oftenenter into a management agreement with the seller. The seller may ormay not be the operator of the properties. Under the managementagreement, the seller is paid a fee for the day-to-day management of thesubject interest. Typically, the Service has required that managementagreements be terminable by the buyer within a short period of time (i.e.,30 days). While this seems inconsistent with the way properties are actuallyoperated in the oil and gas industry, this author’s guess is that the Servicewas concerned that a long-term operating or management agreement at afixed overhead rate could be some sort of a disguised compensation to theseller. By requiring that the investor have the option to terminate in ashort period of time, the Service eliminates the need to look behind thefee schedule to establish that there is no disguised compensation in themanagement arrangement. As a result, this author believes that, if theparties were to establish the fair market value of the management fee,there is no apparent need to give the investor a short-term cancellationoption.

• Pre-tax Profit Expectation.Probably the most controversial issue associated with the pay-as-you-

go structure is the lack of a cash-on-cash return. If one accumulates theentire purchase price, both the hydrocarbon component and the creditcomponent, and views such price in relationship to the cash flow from theproperty, the transaction would be expected to have a negative cash flow.However, it seems improbable that the credit value should be added to thepurchase price but not considered in evaluating an investor’s cash flow ina section 29 transaction. It seems more appropriate that the transaction beevaluated by excluding both (i) the cost of the credit portion of the purchaseprice and (ii) the tax savings in determining whether the purchase of the

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84 C.f. discussion at footnotes 62 to 71, supra and accompanying text.


412

hydrocarbons would have generated a pre-tax cash flow. The credit valueshould be taken out of this determination completely because the value ofthe credit is exclusively tax savings. There is no pre-tax or cash flowbenefit to be derived from the section 29 credit. It appears to this authorthat the Service has implicitly acquiesced in this analysis by issuing theseprivate rulings.

As a variation to the pay-as-you-go structure, the amount of thepurchase price attributable to the credit value could be paid at closing.The amount of the payment would be an estimation of the credit value (afixed percentage of the credit, such as 75 percent of the credit, which issubject to negotiation between buyer and seller) and discounted back inan appropriate rate to the date of closing. The buyer and seller could alsoagree that the purchase price would be adjusted either annually or quarterlyto the extent that the actual production levels differ from the expectedproduction curve estimated by the engineer at the time of closing.85 It ispossible that the buyer would receive advantageous tax treatment byincluding the payment amount in its basis rather than treating suchpayments as contingent debt under the pay-as-you-go structure.86

As another variation, the seller, who owns a working interest, maywant to retain the working interest and sell a royalty or net profits interestcarved-out of the working interest. The buyer, as owner of a royalty or netprofits interest, is treated as owning an economic interest in the propertyand is entitled to claim the section 29 credit on his share of the grossproceeds from the sale of the “qualified fuel.” However, one shouldrecognize that the share of the section 29 credit apportioned to the holderof a net profits interest may be less than expected. Under the applicablerulings, the net profits interest holder is entitled to claim a share of grossproceeds equal only to the amount of “net profit” earned under the termsof the net profits conveyance.87 Thus, if the net profits interest does not

85 While not without risk, this arrangement appears more viable for properties with

predictable production streams.86 The application of the recently-issued contingent payment rules and the amount ofthe depletable basis of the buyer are beyond the scope of this chapter. See, however,Treas. Regs. §§ 1.1012-1(g), 1.1275-4, 1.1274-2(g) and 1.1012-1(g)(1)(issued June 11,

1996).87 See Rev. Rul. 92-25, 1992-1 C.B. 196.

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earn a net profit during a calendar year, the holder of such interest doesnot earn any tax credits.

[1] — Partnership with Special Allocations.In the event that an outright sale of the property to an unrelated party

is not viable, the section 29 credit may be shifted, in part, to the investor/partner by using special allocations within a partnership. Under thisstructure, the economic interest in the property is transferred to thepartnership by the former owner/partner through either a sale orcontribution.88 The investor/partner(s) is entitled to claim the amount oftax credits under section 29 relative to his share of gross proceeds fromthe sale of partnership production allocated to such partner under the termsof the partnership agreement. The investor/partner’s share of grossproceeds may be disproportionate to such partner’s equity capital. Inaddition, single or multiple payout allocations can also be used to shiftthe revenue (as well as the corresponding tax credits) and expenses betweenpartners, as appropriate.89

The parties could enhance the attractiveness of the investment to aninvestor/partner (i.e., reducing the purchase price of the investment) bydecreasing the anticipated cash flow to such investor/partner. This couldbe accomplished by allocating a disproportionate share of expenses(relative to such investor/partner’s share of gross proceeds from the saleof qualified production) to the investor/partner. The expenses allocated tosuch investor/partner may include a management fee, charged by the otherpartner for managing the affairs of the partnership. The disproportionateallocation of expenses to the investor/partner will decrease the cash flowto such partner (and correspondingly increase the cash flow to the formerowner/partner).90

88 If structured as a contribution, close attention should be paid to the disguised sales

rules under I.R.C. § 707(a). See Prop. Treas. Reg. § 1.707-3.89 Care must be taken to ensure that the allocations in the partnership have substantial

economic effect. See Treas. Reg. § 1.704-1(b).90 An added benefit of the partnership structure is that the former owner/partner maybe able to keep a portion of the reserves (attributable to its current interest in the

partnership) on its books for financial purposes.

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The two keys of the partnership structure are that (a) the investor istreated as a partner throughout the term of the partnership, and (b)substantial economic effect is given to the allocation of (i) the grossproceeds from the sale of the qualified production and (ii) expenses ofsuch production. As a precaution to the “status of partner” risk, the formerowner/partner should not have the right to terminate (or buy at other thanfair market value) the interest of the investor/partner. As a precaution tothe “allocations” risk, the partnership agreement should comply with oneof the safe harbors contained in the regulations under section 704(b).

To the extent the section 29 property is acquired by a partnership, dueconsideration should be given to the potential application of the Treasuryregulation addressing abusive partnership transactions.91 This regulationgives the Service the authority to recast a partnership transaction asappropriate to achieve tax results consistent with the intent of subchapterK (the partnership provisions) of the Code.92 Under this regulation, theService may, among other things, disregard a purported partnership inwhole or in part, not treat one or more of the purported partners as apartner, and disregard or reallocate the allocations of the partnership’sitems of income, gain, loss, deduction, or credit.93 The Service mayexercise this authority if a partnership is formed or availed of in connectionwith a transaction or series of related transactions with a principal purposeof substantially reducing the present value of the partners’ aggregate federaltax liability in a manner inconsistent with the intent of subchapter K ofthe Code.94 Whether a partnership was formed or availed of with such aprincipal purpose is determined based on all the facts and circumstances,including a comparison of the purported business purpose for thetransaction and the claimed tax benefits resulting from the transaction.95

The motivation to use a partnership to acquire section 29 propertiesshould not be viewed as the type of motivation which is objectionableunder case law. Section 29 was enacted as a stimulus to the production of

91 Treas. Reg. § 1.701-2 (issued Dec. 29, 1994, amended April 12, 1995).92 Treas. Reg. § 1.701-2(b).93 Treas. Reg. §1.701-2(b)(1)-(5).94 Id.95 Treas. Reg. § 1.701-2(c).

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fuels from nonconventional sources.96 Therefore, a transaction using apartnership to enable several taxpayers to share section 29 tax creditsderived from a property acquired by such partnership should not be viewedas one with the objectionable purpose of tax avoidance.97 It is permissibleand appropriate for investors in a partnership to consider the benefits tobe derived under section 29 of the Code in connection with theirinvestment.98

The recently-issued anti-abuse regulations may have a chilling effecton the use of partnerships in section 29 transactions. Until the Serviceissues a private letter ruling involving a partnership utilizing the pay-as-you-go structure, it will be difficult to determine whether the Servicebelieves the structure is abusive under these recently-issued regulations.

[2] — Royalty Trust Holding Qualifying Interest.A royalty trust allows public investors to acquire, through their

ownership of units in the trust, royalty interests burdening section 29properties. Each holder of units in the royalty trust is taxed directly on his

96 S. Rep. No. 96-394, 96th Cong., 1st Sess. 87 (1979), reprinted in 1980-3 C.B. 205(“alternative energy sources typically involve new technologies, and some subsidy isneeded to encourage these industries to develop to the stage where they can be competitive

with conventional fuels”).97 See Treas. Reg. § 1.6662-4(g)(2)(ii)(“[t]he principal purpose of an . . . arrangementis not to avoid or evade federal income tax if the . . . arrangement has as its purpose theclaiming of . . . tax benefits in a manner consistent with the statute and Congressionalpurpose”); Frank Lyon Co. v. United States, 435 U.S. 561, 580 (1978)(“tax laws affectthe shape of nearly every business transaction”); Sacks v. Commissioner, 95-2 U.S.T.C.¶50,586 (9th Cir. 1995)(absence of pre-tax profitability does not show whether transactionhas economic substance beyond creation of tax benefits in situation in which Congresspurposely used tax incentives to induce investment that otherwise would not have beenmade); Fox v. Commissioner, 82 T.C. 1001, 1021 (1984)(“[w]e acknowledge that many. . . tax-motivated transactions are congressionally approved and encouraged”); cf. Rev.Rul. 79-300, 1979-2 C.B. 112, 113 (legislative history indicates that profit motive notrequired in activities to provide low-income housing because Congress intended to

encourage investment in such activities with tax incentives).98 By retaining an interest in the cash flow from the property, the seller may increasethe attractiveness of the transaction to the purchaser because the production paymentburden reduces the purchase price of the burdened interest. The reduced purchase price,in turn, enhances the after tax rate of return of the purchaser. However, the productionpayment may reduce the anticipated cash-on-cash return of the buyer.

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pro rata share of trust income and deduction (including trust administrativeexpenses) and is entitled to claim his pro rata share of the section 29credit. The royalty income earned by the trust would also be subject to anallowance for cost depletion or percentage depletion. The sale of gas bythe royalty trust can be arranged either to allow cash returns to rise andfall with natural gas prices or to eliminate certain return risks associatedwith fluctuating prices.

The royalty trust is a grantor trust formed under Delaware (or otherstate) law for the purpose of owning royalty or net profits overriding royaltyinterests. The income, expenses and credits from the royalty trust are nottaken into account in computing an investor’s passive activity incomeand loss, and therefore may be used to offset the investor’s regular taxliability from any source, whether passive or active, subject only to otherlimitations affecting the individual investor’s tax circumstances. As a result,royalty trust units tend to be more attractive to individuals or closely heldcorporations otherwise subject to the passive activity limitations set forthin section 469.

In a royalty trust, the size of the units can be tailored to allow individualinvestors to reap the maximum advantages of investing in section 29properties. Each investor can choose the size of the interest (by determiningthe appropriate number of units to purchase) on the basis of such investor’sparticular tax circumstances. Also, as noted above, the section 29 creditresults in the cash distributions from the royalty trust being partially orfully sheltered from federal income tax, with the possibility of additionaltax credits to reduce taxes on income from other sources. As a minorvariation, the royalty trust can also use a portion of the investment proceedsto acquire Treasury obligations, thereby ensuring a return or the investor’s“principal” at termination.

§ 13. 06. Conclusion.There is a high level of interest in the tax advantages associated with

the ownership of section 29 properties. It is expected that this interestwill continue or increase in light of current marginal federal income taxrates. Given the complexity of the issues affecting an investor’s right toclaim (and support) its ownership of an economic interest in a qualifyingproperty, care must be taken in structuring these transactions to ensure

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that the credit is transferred to the investor. An advisor must evaluate allaspects of a particular transaction in providing guidance either to the selleror the investor. Finally, attention must be given to continued guidancefrom the Internal Revenue Service. This guidance, usually in the form ofprivate rulings, will affect structures utilized in future years as a methodfor monetizing the tax benefits associated with section 29 properties.

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