cite as energy & min. l. inst. chapter 12 tax issues in the disposition of oil & gas...

CITE AS33 Energy & Min. L. Inst. 12 (2012)

Chapter 12

Tax Issues in the Disposition of Oil & Gas Assets

Gregory V. NelsonPaul Hastings LLP

Houston, Texas1

Synopsis§ 12.01. Purchase and Carry Transactions ................................................. 410 [1] — The Transaction ........................................................................ 410 [2] — Example of Typical Transaction .............................................. 410 [3] — Structure as a Tax Partnership ................................................. 411 [4] — Disguised Sale/Reimbursement of Preformation Costs ............................................................... 413 [5] — Allocation of Intangible Drilling Costs ................................... 415 [6] — Allocation of Cost Depletion ................................................... 416 [a] — Keep Your Own .............................................................. 417 [b] — Book-up/Remedial 704(c)/Simulated Depletion ....................................................................... 418 [7] — Capital Account Maintenance ................................................. 421§ 12.02. Oil and Gas Asset Sales ....................................................................422

[1] — Transfer with No Retained Interest..........................................422[2] — Transfer with Retained Royalty Interest ..................................423[3] — Transfer with Retained Production Payment ..........................424[4] — Volumetric Production Payment ..............................................426

§ 12.03. Like-Kind Exchanges of Oil and Gas Assets .................................428[1] — Like-Kind Exchanges — Background .....................................428[2] — The “Exchange” Requirement .................................................429[3] — “Held For” Requirement .......................................................... 433[4] — “Like-Kind” Requirement........................................................ 433[5] — Withdrawal of Properties from a Tax Partnership ..................434[6] — Section 704(c)(1)(B) .................................................................434[7] — Section 737 ............................................................................... 435

1 IRS Circular 230 Disclaimer: As required by U.S. Treasury Regulations governing tax practice, you are hereby advised that any written tax advice contained herein was not written or intended to be used (and cannot be used) by any taxpayer for the purpose of avoiding penalties that may be imposed under the Code.

ENERGY & MINERAL LAW INSTITUTE

410

§ 12.01

[8] — Examples .................................................................................. 435[a] — Tax Partnership — Example 1 ....................................... 435[b] — Tax Partnership — Example 2 .......................................436[c] — Tax Partnership — Example 3 ...................................... 437

§ 12.04. Recent Developments in Upstream Master Limited Partnerships (MLPs) and Royalty Trusts .....................................439

[1] — Upstream Royalty Trust Taxed as Partnership ......................... 439[2] — Royalty Trusts — Trust for Tax ................................................440[3] — Royalty Trusts — Partnership for Tax ......................................440[4] — Types of Conveyances ...............................................................442

[a] — Types of Properties ..........................................................442[b] — Tax Characteristics .........................................................442

§ 12.01. Purchase and Carry Transactions.[1] — The Transaction.A typical oil and gas purchase and carry transaction involves two or

more participants. The first participant owns the oil and gas lease that the participant desires to develop. The second (and, in some cases, third) participant has cash that the participant would like to invest in (1) the purchase of a portion of the oil and gas asset from the first participant and (2) the payment of its share of development costs for the property and the payment of at least a portion of the first participant’s share of the development of the property.

The first participant may be motivated to enter into the transaction to attract equity investors to the property in order to transfer the risk of ownership and the cost of development of the oil and gas assets to the second participant. The second participant is motivated by the opportunity to invest in existing oil and gas assets on which the first participant may have already completed pre-development work.

[2] —Example of Typical Transaction.For purposes of our discussion of the tax issues involved in a typical

purchase and carry transaction, the following example is instructive:• A owns an oil and gas property valued at $100.• B pays A $50 of cash in exchange for a 50 percent interest in A’s

original interest in the property.

TAX ISSUES IN THE DISPOSITION OF OIL & GAS ASSETS

411

§ 12.01

• B also agrees to pay A’s 50 percent share of drilling costs to the extent of a total of $30.

In summary, B has “purchased” a 50 percent interest in the property and is “carrying” A’s drilling costs to the extent of $30.

[3] —Structure as a Tax Partnership.Even though the parties hold the oil and gas properties as tenants in

common for oil and gas title purposes, the parties are considered to be partners in a tax partnership unless they agree to elect out of Subchapter K for federal income tax purposes.2

The federal tax law provides that two (or more) persons will be considered to be partners for federal income tax purposes if they carry on a trade, business, financial operation or venture and divide the profits therefrom.3 A contractual relationship in which the parties have a joint profit motive with respect to an asset will cause the contracting parties to be partners for federal income tax purposes.

Subchapter K of the Internal Revenue Code of 1986, as amended (the “Code”), permits the contracting parties to elect to not be partners for federal income tax purposes with respect to an oil and gas asset if they

(i) own the oil and gas property as co-owners either of the fee, or under lease or other contractual relationship;

(ii) reserve the right to take in kind their separate share of the oil and gas produced; and

(iii) do not jointly sell the oil and gas produced or extracted, although each party may delegate authority to sell his share of the property produced or extracted, but not for a period of time in excess of the minimum needs of the industry, and in no event for more than one year.4

2 Treas. Reg. § 1.761-2(a)(3).3 Id. § 301.7701-1(a)(2).4 Id. § 1.761-2(a)(3).


412

Unless the participants elect out of Subchapter K of the Code, the parties to a typical venture agreement, participation agreement, or joint operating agreement are partners for federal income tax purposes. They must file a partnership tax return and distribute Forms K-1 to the parties. The parties also enjoy the benefits of and bear the burdens of Subchapter K — many of which are traps for the unwary or manna from heaven depending on the circumstances.5

Even though A and B continue to hold title to their oil and gas interests in their own names, A and B agree not to elect out of Subchapter K of the Code. Therefore, A and B are deemed to own their oil and gas interests for tax purposes through AB Partnership.6

Because A and B have not elected to be excluded from Subchapter K of the Code, the “purchase and carry” transaction described in the example may be diagramed as follows:

5 A tax partnership arrangement may also be used in situations where the pool of capital doctrine does not apply. In I.R.S. Gen. Couns. Mem. 22730, 1941-1 C.B. 214, the IRS held that a person who paid drilling costs on a lease in exchange for an interest in the lease did not recognize compensation income. 1941- C.B. at 221-22. In Rev. Rul. 77-176, 1977-1 C.B. 77, the IRS held that the pool of capital doctrine announced in Gen. Couns. Mem. 22730 does not apply in the situation where a participant paid drilling costs in partial exchange for an interest in acreage outside the drill site. Since then, the industry has avoided the restrictions of Rev. Rul. 77-176 by subjecting the drill site and the non-drill site acreage to a tax partnership arrangement and by granting interests in the tax partnership that replicate the economic interests of the participants in the non-drill site acreage. 6 AB Partnership will not usually be considered to be a partnership for state law purposes. Luling Oil & Gas Co. v. Humble Oil & Refining Co., 191 S.W.2d 716, 722 (Tex. 1946).

§ 12.01


413

1A. A contributes property to AB Partnership

1B. B contributes $50 in cash to AB Partnership

2. AB Partnership distributes $50 in cash to A.

[4] —Disguised Sale/Reimbursement of Preformation Costs.B is deemed to have contributed its $50 of cash to the AB partnership.A is deemed to have sold to AB partnership 50 percent and is deemed

to have contributed to AB partnership the other 50 percent of the oil and gas property.7

A recognizes gain on the sale to AB Partnership, but may exclude cash deemed received from AB Partnership from A’s amount realized to the extent that the cash reimburses A’s capital costs incurred to acquire or develop the contributed property within the 24 months preceding the date of the deemed contribution to AB.8

The gain recognition exception for reimbursement of preformation costs may only be used to the extent of 20 percent of the fair market value of the contributed property.9 This limit does not apply if the fair market value of

7 Treas. Reg. § 1.707-3(b); -3(f) (Ex. 1).8 Id. § 1.707-4(d).9 Id. § 1.707-4(d)(2)(ii).

§ 12.01


414

the contributed property is not more than 120 percent of the contributed property’s adjusted tax basis at the time of contribution.10

In order to take advantage of the preformation exception, the parties should take care to create a flow of funds from the cash contributor (participant B) to the partnership (AB partnership) and from the partnership (AB partnership) to the property contributor (participant A). Because AB partnership is not a state law entity, it will not have title to its own assets. In order to more clearly establish the flow of funds, A and B should therefore establish a separate bank account for the AB partnership into which to contribute B’s funds before they are distributed to A.

The tax advantages of the use of the preformation exception can be demonstrable.

Example: Assume that A has a tax basis of $30 in the contributed property and has invested $10 to purchase or improve the contributed property in the preceding 24 months. The $30 of tax basis is divided equally between the sale portion and the contribution portion of the contributed property.

Sale Portion Contribution Portion Amount Realized $50 Tax Basis (50 percent of $30) $15 Less: Preformation Less: Preformation Reimbursement (10) Reimbursement (10) Net Amount Realized $40 Tax Basis in interest in AB $5 Less: Tax Basis (50 percent of $30) (15) Gain on Sale $25

In the example, A has effectively deferred $10 of gain that would have otherwise been recognized upon the receipt of the cash in exchange for the sale of 50 percent of the assets if the preformation exception had not been available.11 The exception is only available if the parties do not elect out of Subchapter K.

10 Id.11 The $10 of gain will be recognized when A sells its share of the deemed contributed properties.

§ 12.01


415

[5] — Allocation of Intangible Drilling Costs.If no tax partnership is used (i.e., A and B elect out of Subchapter K),

B must capitalize the intangible drilling and development costs (“Drilling Costs”) that it pays on behalf of A and may only deduct the Drilling Costs attributable to B’s interest. The regulations provide:

in any case where any drilling or development project is undertaken for the grant or assignment of a fraction of the operating rights, only that part of the costs thereof which is attributable to such fractional interest is within this option. In the excepted cases, costs of the project undertaken, including depreciable equipment furnished, to the extent allocable to fractions of the operating rights held by others, must be capitalized as the depletable capital cost of the fractional interest thus acquired.12

Returning to our example, assume that the parties incur $100 of Drilling Costs. Under the carry arrangement, B pays its $50 share (50 percent) and pays $30 of A’s $50 share (50 percent) of the Drilling Costs. A pays the remaining $20 share of its 50 percent share of the Drilling Costs.

Under the regulation quoted above, B may deduct $50 of Drilling Costs attributable to B’s 50 percent interest in the property but must capitalize $30 of Drilling Costs into its depletable basis in the property because the $30 is attributable to operating rights held by others (A). B may recover its $30 of capitalized Drilling Costs through either percentage or cost depletion.13

The AB tax partnership allows the partnership to acquire the property and to incur the Drilling Costs. In this situation because the Drilling Costs

12 Treas. Reg. § 1.612-4(a).13 A may deduct the $20 of Drilling Costs that it pays attributable to its 50 percent interest in the property. A tax partnership would not be necessary if B were entitled to the first $80 of income from the developed property. If B is entitled to all of the income from the property until B has recouped all the Drilling Costs that B has funded (the “payout period”), B is deemed to own all of the fractional interests in the lease during the payout period and may therefore deduct all of the Drilling Costs notwithstanding the restrictions on deductibility imposed by Treas. Reg. § 1.612-4(a). Rev. Rul. 69-332, 1969-1 C.B. 87, and Rev. Rul. 71-207, 1971-1 C.B. 160.

§ 12.01


416

are incurred by the partnership (and not by A or by B), there are no “operating rights held by others” because all of the operating rights that are held of record by A and by B are held by the partnership for federal income tax purposes. Therefore, Treas. Reg. § 1.612-4(a) does not apply.14

The Code allows the partners in a partnership broad discretion in allocating income, gain, loss and deductions attributable to partnership activity among the partners and those allocations will be respected if they have substantial economic effect.15 Therefore, the AB tax partnership may specially allocate the Drilling Costs to the contributor of those costs.16

A typical tax partnership agreement provides that “the deduction attributable to costs incurred by a party with respect to the Property shall be allocated to the party that bears such costs.” Therefore, in the example, for federal income tax purposes, AB partnership would allocate to B $80 of the $100 of Drilling Costs, and AB partnership would allocate to A $20 of the $100 of Drilling Costs.

[6] —Allocation of Cost Depletion.In the case of an oil and gas property held by a partnership, the allowance

for depletion of the property is computed separately by the partners and not by the partnership.17 The partnership allocates the tax basis of its oil and gas properties among its partners, and then such partners compute either cost or percentage depletion with respect to that allocated tax basis.18 A partnership agreement may allocate tax depletable basis to the partners as long as capital accounts are adjusted for depletion deductions (either actual or simulated) and as long as, upon sale of the property, the partnership’s amount realized

14 I.R.S. Tech. Adv. Mem. 8133021 (April 20, 1981).15 I.R.C. 704(b). The principles of “substantial economic effect” are discussed at § 12.01[7], infra.16 Treas. Reg. § 1.704-1(b)(5)(Ex. 19 (i)); Rev. Rul. 68-139, 1968-1 C.B. 311.17 I.R.C. 613A(c)(7)(D); Treas. Reg. § 1.613A-3(e)(1).18 Id.

§ 12.01


417

is first allocated to the partners who were allocated the tax basis to the extent of the partnership’s simulated adjusted basis19 in the property.20

There are two usual choices for cost depletion of AB partnership:

• Keep Your Own • Book-up/Remedial 704(c)

[a] — Keep Your Own.The Section 704(c) regulations are usually very careful about preserving

the tax benefits of the cash contributor to a partnership. The Section 704(c) regulations generally provide that, when a low basis depreciable asset is contributed to a partnership, the tax benefits of the depreciation must be allocated to the existing partners or to the cash-contributing partners.21

Notwithstanding the apparent bias of the Section 704(c) regulations, the regulations appear to sanction a method by which the partner who contributed the depletable property will be entitled to all of its tax depletion so long as the contributing partner is allocated any built-in gain associated with the contributed property if it is later disposed of by the partnership. In an example in the regulations, a partner contributes an oil and gas property with a tax basis of $10,000 and a fair market value of $100,000. The partnership agreement allocates the entire depletable basis to the property-contributing partner, and, accordingly, all the depletable deductions would be for the account of such partner since a partnership may only allocate depletable basis among its partners and may not allocate depletion deductions among its partners. The regulation holds that as long as upon a sale of the property the property

19 Since the partnership has no tax basis in an oil and gas property and therefore may not claim depletion deductions for federal income tax purposes, the partnership maintains a fictional (or simulated) basis for capital account purposes and takes fictional (or simulated) depletion deductions with respect to that simulated basis. Treas. Reg. § 1.704-1(b)(2)(iv)(k)(2). Alternatively, the partnership may collect actual depletion data from each partner and use that data to make adjustments to the capital accounts. Treas. Reg. § 1.704-1(b)(2)(iv)(k)(3). 20 Treas. Reg. § 1.613A-3(e)(5) states that the basis allocation rules of the Section 613A regulations yield to the allocations of basis sanctioned by Treas. Reg. § 1.704-1(b)(4)(v).21 Id. § 1.704-3(b)(1); -3(b)(2)(Ex. 1)(ii) (describing allocations of tax depreciation to permit a cash contributing partner to obtain all of the partnership’s tax depreciation to the extent of the cash contributing partner’s share of the partnership’s book depreciation.

§ 12.01


418

contributing partner is allocated an amount of amount realized so that the property contributing partner is allocated $90,000 of built-in gain (adjusted for future simulated depletion deductions), the allocations are approved.22

This “keep your own” method was also discussed (but not adopted) in the preamble to the final regulations for Section 704(c) of the Code.23 Commentators had urged its adoption as an additional reasonable Section 704(c) method. The Treasury Department stated:

The comments also suggested including as a specifically described reasonable method an allocation method used in the oil and gas industry. Under this method, each partner is, in essence, allocated all of the depreciation or depletion from each item of property the partner contributes to the partnership (or from property purchased with cash contributed by that partner). Upon disposition of the contributed property, remaining built-in gain or loss is allocated to the contributing partner, and any additional gain or loss is allocated according to the partnership agreement. The IRS and Treasury have also decided not to add this method as a specific reasonable method described in the final regulations because, although it may be common in the oil and gas industry, it does not appear to be a generally applicable method. However, the use of this method in appropriate situations may be reasonable. The IRS is considering issuing further guidance on this method.24

The IRS has approved the “keep your own” method in at least two private rulings.25

In our example, under the “keep your own” method, A retains the $5 of tax basis attributable to the contributed portion of the property contributed by A and continues to claim depletion with respect to that property. Assuming that the property has a remaining depletable life of 5 years, A would claim a $1 depletion deduction each year.

22 Id. § 1.704-1(b)(5)(Ex. 19 (iv)).23 T.D. 8500, 1994-1 C.B. 183.24 T.D. 8500, 1994-1 C.B. 183-84.25 PLRI.R.S. Priv. Ltr. Rul. 9829016 (July 17, 1998) and Priv. Ltr. Rul. 9829045 (July 17, 1998).

§ 12.01


419

[b] — Book-up/Remedial 704(c)/Simulated Depletion.The remedial method of Section 704(c) allows the partners to elect to

allocate deductions to the cash-contributing partner that would exceed the so-called ceiling rule and make up for those “remedial deductions” by allocating an equal amount of “remedial income” to the contributing partner.26 In our example, the contributed portion of the contributed property has a tax depletable basis of $5, but each partner has a book depletable basis of $25 (50 percent of $50 fair market value of the portion of the property contributed by A). Under the traditional method of allocations under Section 704(c) one would presume that the $5 of tax depletable basis would be allocated to B, the cash contributor. But, because the contributed property has only $5 of tax depletable basis, B would not be entitled to tax depletion deductions attributable to the remaining $20 of its $25 of book basis in the property. The ceiling rule does not allow the shift of more than all of the tax attributes of the partnership to the cash-contributing partner.27

There is no indication in the remedial allocation rules on how to treat an oil and gas property under the remedial method. If the remedial method is to apply, the partnership agreement must allocate a book depletable basis to the cash contributing partner based upon its economic interest in the contributed property and, to the extent that the cash contributing partner’s share of the contributed property’s book depletable basis exceeds the tax depletable basis of the contributed depletable property, the contributing partner would be allocated a negative book depletable basis. The contributing partner would then be allocated remedial taxable income to account for its negative book depletable basis over the life of the depletable asset. In our example, AB tax partnership books up the contributed portion of the contributed property to its fair market value of $50,28 which book depletable basis is allocated 50 percent to A and 50 percent to B.

Assuming that the property has a remaining depletable life of 5 years, each of A and B would be allocated approximately $5 of book depletion per

26 Treas. Reg. § 1.704-3(d)(1).27 Id. § 1.704-3(b)(1); -3(b)(2) (Ex. 1 (ii)).28 Recall that AB tax partnership purchased half of the property from A for $50 and that A contributed the other half of the property. The example is only concerned with the book and tax depletable basis attributable to the contributed portion of the property.

§ 12.01


420

year, B would be allocated $1 of tax depletion per year and $4 of remedial depletion per year, and A would be allocated $4 of remedial income per year.

These results are made possible by allocating to B all of A’s tax depletable basis in the property. Then, B is allocated $20 of depletable basis for remedial method purposes. In order to balance the remedial accounts, A is allocated $20 of “negative” depletable basis for remedial method purposes. B then recovers its remedial basis with remedial depletion deductions, and A takes remedial income into account to support the remedial depletion deductions enjoyed by B.

Over the course of the first five years of the partnership’s existence, the depletion allocations would be as follows: A B Book Tax Remedial Book Tax Remedial

25 5 25 0

Tax Depletable Basis (5) 5

Remedial Book Basis (20) 20

Year 1 (5) 0 4 (5) (1) (4) 20 0 (16) 20 4 16

Year 2 (5) 0 4 (5) (1) (4) 15 0 (12) 15 3 12

Year 3 (5) 0 4 (5) (1) (4) 10 0 (8) 10 2 8

Year 4 (5) 0 4 (5) (1) (4) 5 0 (4) 5 1 4

Year 5 (5) 0 4 (5) (1) (4) 0 0 0 0 0 0

Over the course of the five-year period, B has received the tax benefit of the $25 of book basis — $5 through actual depletion deductions and $20 through remedial deductions. A made these deductions possible by allocating the entire tax depletable basis ($5) to B and by absorbing $20 of remedial income.

§ 12.01


421

[7] — Capital Account Maintenance.The Drilling Costs may only be specially allocated to B if the allocations

have substantial economic effect.29 In general, the allocations are deemed to have economic effect if (1) the capital accounts of the partners are maintained in accordance with the requirements of Treas. Reg. § 1.704-1(b)(2)(iv); (2) the amounts due a partner upon liquidation of the partnership are determined using the positive capital account balances of the partners; and (3) if a partner has a negative capital account balance on liquidation of the partnership, the partner with the negative capital account will restore its negative capital account by making a capital contribution to the partnership, the proceeds of which will be paid to creditors or distributed to partners with a positive capital account.30

Because all book deductions are not allocated in accordance with the 50/50 deal (e.g., specially allocated IDC deductions), AB must use capital account mechanics in order to specially allocate the deductions to the party who paid the cost.

The beginning capital accounts would be as follows: A B Contribution 100 50 Distribution at formation (50) 0 50 50

B then contributes $80 for Drilling Costs and A contributes $20 for Drilling Costs. A B 50 50 Drilling Cost Contribution 20 80 70 130 Drilling Cost Deduction (20) (80) 50 50

Therefore, if the deductions are allocated to the contributor, the capital accounts remain in the 50/50 relationship on liquidation. If, for any reason,

29 Treas. Reg. § 1.704-1(b)(1)(i).30 Id. § 1.704-1(b)(2)(ii).

§ 12.01


422

the capital accounts are not 50/50 on liquidation, then the tax partnership agreement allocates the book income and book gain on liquidation to cause the capital accounts to be as nearly as possible in the 50/50 ratios.

If there is not enough book income and book gain on liquidation to equalize the capital accounts, then the parties convey interests in the lease for no consideration so that AB has effectively liquidated in accordance with the capital account balances of the parties. As an example, if at the time of liquidation of AB tax partnership, A had a negative capital account of $50 and B had a positive capital account of $50, A would convey to B an undivided interest in A’s oil and gas properties that has a fair market value of $50. The conveyance would be treated as a capital contribution by A to AB tax partnership and a distribution by AB tax partnership to B to “zero out” their capital accounts.

Alternatively, the parties could make a cash payment to each other to settle the negative capital account. A could make a $50 cash payment to B. For capital account purposes, this payment would be recorded as a deemed capital contribution by A and a deemed distribution to B. The cash payment would be designed to cause the capital accounts of each party to equal zero after taking into account a deemed distribution to each party of its interest in the lease that was subject to the tax partnership agreement.

§ 12.02. Oil and Gas Asset Sales.[1] —Transfer with No Retained Interest.The standard oil and gas property disposition structure involves the sale

of all of seller’s interest in the oil and gas lease or the sale of an undivided interest in seller’s interest in the oil and gas lease. This transaction is characterized as a sale or exchange of the transferred lease for federal income tax purposes.31 As an illustration,

A owns an oil and gas lease and transfers the lease to B for a cash payment. A retains no interest in the transferred lease.

31 Prichard v. Helvering, 310 U.S. 404 (1940).

§ 12.02


423

A recognizes Section 1231 capital gain (subject to IDC and depletion recapture) on the sale and offsets the amount realized against A’s tax basis in the lease.

B obtains a depletable tax basis in the acquired lease equal to the cash paid.

[2] — Transfer with Retained Royalty Interest.A transfer of an oil and gas lease with the retention of a non-operating

interest (e.g., an overriding royalty or net profits interest royalty) with a life co-terminous with the transferred lease is considered not to be a sale or exchange for federal income tax purposes. Instead, the federal income tax law characterizes the transfer as a sublease.32 This characterization for federal income tax purposes may come as a shocking surprise since the transaction is considered a sale for commercial and for state law purposes. As an illustration,

A owns an oil and gas lease and transfers the lease to B in exchange for a $100 cash payment. A retains a five percent royalty interest in the transferred lease.

32 Burton-Sutton Oil Co. v. Comm’r, 328 U.S. 25 (1946); Palmer v. Bender, 287 U.S. 551 (1933); Rev. Rul. 69-352, 1969-1 C.B. 34.

§ 12.02


424

A treats the $100 of cash received as a lease bonus. The payment does not qualify for capital gain sale treatment and may not be offset by A’s tax basis in the lease.33 A’s tax basis in the lease is transferred to the retained royalty interest and becomes A’s tax basis in the retained royalty interest.34 A reports royalty income received with respect to the royalty interest and continues to claim depletion on the royalty interest.35

B capitalizes $100 of the lease bonus into the acquired lease. B is permitted to claim cost depletion to recover its $100 of lease bonus investment.36

[3] — Transfer with Retained Production Payment.A transfer of an oil and gas property with the retention of a non-operating

interest that is not co-terminous with the transferred lease is characterized as a sale or exchange of the transferred lease.37

A production payment may be structured to allow the seller to retain economics in the lease that it disposed of that are very similar to a retained royalty interest but with remarkably different tax results. As an example, assume that

A owns an oil and gas lease and transfers the lease to B in exchange for a $100 cash payment. A retains a volumetric production payment in the transferred lease that entitles A to 5 percent of the production from the lease but for a time period that is not co-terminous with the leasehold interest that was sold to B.

33 Rev. Rul. 69-352, 1969-1 C.B. 34; Crooks v. Comm’r, 92 T.C. 816 (1989).34 I.R.S. Gen. Couns. Mem. 22730, 1941-1 C.B. 214, 216. 35 Id. 36 I.R.S. Gen. Couns. Mem. 22730, 1941-1 C.B. 214, 217; Rev. Rul. 77-176, 1977-1 C.B. 77, 80.37 Treas. Reg. § 1.636-1(a)(1)(i); I.R.S. Gen. Couns. Mem. 22730, 1941-1 C.B. 214, 217-18.

§ 12.02


425

A volumetric production payment is very similar to a retained royalty interest, except that the interest terminates when a certain percentage (say, 80 percent) of the known reserves at the time of the creation of the production payment has been produced.

The IRS has ruled that, if a seller sells its lease for cash, a production payment based upon reserves currently known to exist, and a contingent interest in reserves that might exist after the production of reserves currently known to exist, the seller is entitled to sale or exchange treatment. The IRS ruled that the seller was entitled to sale or change treatment notwithstanding the seller’s contingent interest in future reserves. The IRS ruled that the contingent interest in future to be discovered reserves was not a continuing interest in the lease.38 It is uncertain whether the IRS intended this ruling to be used to allow for the retention of a contingent interest in currently non-productive oil and gas properties and allow the transaction to nevertheless be treated as a sale or exchange of the oil and gas property. The ruling gives parties an opening for how to structure a sale of non-productive properties where the seller desires to retain a continuing interest in the non-productive properties, but also wishes to preserve sale or exchange treatment for the cash received.

A retained interest is considered to be a production payment under Section 636 of the Code if the retained interest:

• is an economic interest in the property;

• may only be satisfied out of production from the property;

• terminates upon a date certain or upon the production of a specified volume of mineral or upon the production of a specified dollar amount of mineral; and

• has an expected economic life (at the time of its creation) of a shorter duration than the economic life of the burdened property.39

38 I.R.S. Priv. Ltr. Rul. 9635035 (June 3, 1996).39 Treas. Reg. § 1.636-3(a)(1).

§ 12.02


426

If the retained interest qualifies as a production payment, the retained interest is characterized as a seller-financed promissory note (with contingent payments) and not as a retained royalty interest.40 The retained production payment allows A to qualify for capital gain sale treatment (subject to IDC and depletion recapture), and A may offset the amount realized against A’s tax basis.41

B capitalizes the cash payment into the depletable basis in the acquired lease.42 B reports all of the taxable income and depletion deductions for the lease (including the portion of the lease burdened by the production payment).43

Under the original issue discount rules, a volumetric production payment is treated as a contingent payment debt instrument because it is a debt instrument (by virtue of Section 636 of the Code) that provides for contingent payments (no payment required except out of production).44 In the situation in which the production payment is issued for nonpublicly traded property (the oil and gas lease), each payment on the volumetric production payment is treated as a contingent principal payment by B to the extent of the present value of the payment discounted at the applicable federal rate to the date on which the production payment was created. The balance of the particular payment is treated as an interest payment by B.45

B deducts the deemed interest amount as the production payments are made and capitalizes the deemed principal payments into its tax basis in the acquired lease as those payments are made.46

[4] — Volumetric Production Payment.A volumetric production payment is an economic interest that terminates

upon the production of a specified volume of mineral and terminates before

40 Id. § 1.636-1(c)(1)(i).41 Id. § 1.636-1(c)(1)(i); -1(c)(1)(ii) (Ex. 1).42 Id. § 1.636-1(c).43 Id. § 1.636-1(a)(1)(ii).44 Id. § 1.1275-4(a)(1). 45 Id. § 1.1275-4(c)(4). 46 Treas. Reg. § 1.1275-4(c)(4)(ii); Treas. Reg. § 1.1275-4(c)(7)(Ex. 1, (iv)).

§ 12.02


427

the expected productive life of the mineral property.47 The regulations require that the production payment “must have an expected economic life (at the time of its creation) of shorter duration than the economic life” of the burdened properties.48 The regulations further explain that an economic life is of shorter duration than the economic life of the burdened property exists “only if such right may not reasonably be expected to extend in substantial amounts over the entire productive life of such mineral property.”49

The IRS has given the oil and gas industry some additional guidance on how to comply with the “of a shorter duration than the life of the burdened property” requirement. In Rev. Proc. 97-55,50 the IRS stated that it will rule that a retained interest will be treated as having an economic life of a shorter duration than the burdened property if

.03 it is reasonably expected, at the time the right is created, that it will terminate upon the production of not more than 90 percent of the reserves then known to exist; and

.04 the present value of the production expected to remain after the right terminates is 5 percent or more of the present value of the entire burdened property (determined at the time the right is created). The determination of present value takes into account all the facts and circumstances, in accordance with the provisions of section 1.611-2(e).51

A retained volumetric production payment is economically very similar to a retained royalty interest, but the properly advised seller who retains a volumetric production payment enjoys Section 1231 capital gain treatment for the gain and is allowed to recover the seller’s capital investment in computing the amount of the gain. In contrast, the seller who retains a perpetual royalty interest includes the cash received as ordinary income and is not permitted to offset its tax basis against the amount received.

47 Treas. Reg. § 1.636-3(a)(1). 48 Id. 49 Id. 50 Rev. Proc. 97-55, 1997-2 C.B. 582.51 Id., §§ 4.03, 4.04.

§ 12.02


428

§ 12.03. Like-Kind Exchanges of Oil and Gas Assets.[1] — Like-Kind Exchanges — Background.Under the federal income tax law the general rule is that upon a sale or

exchange of property, a taxpayer must recognize gain or loss equal to the difference between the seller’s amount realized and its adjusted tax basis.52 Cash and the fair market value of property received by seller are includible in the seller’s amount realized.

A major exception to the general rule applies if the seller engages in a like-kind exchange. The rule generally may be summarized as allowing for no gain or loss to be recognized by the seller if property held for productive use in a trade or business or for investment is exchanged solely for property of a like-kind to be held by the seller either for productive use in a trade or business or for investment.53

The like-kind exchange statute may by summarized as requiring (1) an exchange; (2) the relinquished property to have been held by the seller in a trade or business or for investment; (3) the replacement property must be held by the seller in a trade or business or for investment and (4) the relinquished property and the replacement property must be “like-kind”.

The like-kind exchange statute can be very useful in the oil and gas context, but the taxpayer must be mindful of some traps for the unwary and those who are not fully advised.

First, certain assets do not qualify for like-kind exchange treatment even if they appear to be like-kind. Those assets include corporate stock, bonds, notes, evidences of indebtedness, interests in a partnership and interests in trusts.54

An interest in an arrangement treated as a tax partnership will not qualify as property that may be the subject of a like-kind exchange because for federal income tax purposes:

52 I.R.C. § 1001.53 Id. § 1031.54 Id. § 1031(a)(2). For purposes of the like-kind exchange rules, the transfer of an interest in a disregarded entity is treated as a transfer of the assets owned by the disregarded entity. I.R.S. Priv. Ltr. Rul. 200118023 (May 7, 2001).

§ 12.03


429

• The interest held by the party is a “partnership interest.”

• Therefore, it is not an interest in oil and gas real property.

The statute does contain a helpful exception which provides that

For purposes of this section, an interest in a partnership which has in effect a valid election under Section 761(a) to be excluded from the application of all of Subchapter K shall be treated as an interest in each of the assets of such partnership and not as an interest in a partnership.55

Therefore, if the parties to an oil and gas Joint Operating Agreement arrangement have elected to be partners for federal income tax purposes to take advantage of the benefits described in § 12.01 above, the parties will need to cause the arrangement to elect out of subchapter K in order to complete a Section 1031 like-kind exchange of the subject assets.

[2] — The “Exchange” Requirement.In order to comply with the exchange requirement, there must be a

reciprocal transfer of property, but the exchange need not be simultaneous.56 Notwithstanding the fact that the exchange need not be simultaneous, the taxpayer may not receive any cash from the purchaser.57 Instead, in the situation where the seller disposes of the relinquished property before the seller acquires the replacement property, the purchaser of the relinquished property must deliver its purchase price to a qualified intermediary pending reinvestment in the replacement property.58 The qualified intermediary must be prohibited from delivering any benefit of the cash received from purchaser during the exchange period.59 The exchange period begins with the date of the sale of the relinquished property and ends on the date that is 180 days after the closing of the sale of the relinquished property (or, if earlier, upon the due date (including extensions) of the seller’s tax return for the year of

55 I.R.C. § 1031(a)(2).56 I.R.C. 1031(a)(3); Treas. Reg. § 1.1031(k)-1.57 Treas. Reg. § 1.1031(k)-1(f). 58 Id. § 1.1031(k)-1(g).59 Id. § 1.1031(k)-1(g)(6).

§ 12.03


430

the closing of the sale of the relinquished property). A qualified intermediary may be any person except a person who is actually an affiliate of, or the agent of, the seller, except that rendering services as agent in routine financial, title insurance, escrow and trust services does not disqualify such person from the role of qualified intermediary.60

There is no requirement that an exchange be simultaneous; forward and reverse exchanges are allowed.61 In the case of the deferred forward exchange, the seller typically enters into a contract with purchaser to dispose of the relinquished oil and gas property. The seller assigns the rights to the contract to sell the relinquished property to the qualified intermediary and notifies all of the parties to the contract.62 The purchaser of the relinquished property transfers the purchase price to the qualified intermediary, and the seller transfers title to the property to the purchaser.63

The closing of the sale of the relinquished property starts the clock for identifying and acquiring the replacement property. The seller must identify the replacement property within 45 days after the closing and must acquire the replacement property within 180 days after the closing of the sale of the relinquished property (or, if earlier, upon the due date (including extensions) of the seller’s tax return for the year of the closing of the sale of the relinquished property).64

Therefore, it is a relatively simple matter for the purchaser to accommodate a deferred like-kind exchange. The purchaser must consent to the assignment of the seller’s right to payment to the qualified intermediary, must be willing to accept notice of that assignment and must pay its purchase price to the qualified intermediary (instead of paying the seller directly). The purchaser continues to be in contractual privity with the seller and may enforce its

60 Id. § 1.1031(k)-1(k).61 I.R.C. § 1031(a)(3). 62 Treas. Reg. § 1.1031(k)-1(g)(4)(v).63 Rev. Rul. 90-34, 1990-1 C.B. 154, permits the seller’s deed to bypass the qualified intermediary.64 I.R.C. § 1031(a)(3); Treas. Reg. § 1.1031(k)-1(b)(2)(ii).

§ 12.03


431

contractual rights (including rights of specific performance) against the seller. The exchange need not be non-taxable to the purchaser.65

The seller may identify the replacement property by sending written notice to the qualified intermediary.66 The seller may identify three potential replacement properties without regard to their fair market value or may identify any number of replacement properties so long as the aggregate fair market value of the identified replacement properties does not exceed 200 percent of the fair market value of the relinquished property.67 The penalty for over-identification is that the seller will be treated as not identifying any properties unless the seller acquires identified replacement properties having a fair market value not less than 95 percent of the fair market value of all identified replacement properties or if the property is acquired before the end of the identification period.68

If the seller identifies replacement properties using the “200 percent of fair market value” safe harbor, the seller should be careful about using the sales price of the relinquished property as a proxy for its fair market value. In cases in which the purchaser is acquiring the relinquished property’s oil and gas production as of an “effective date” that is prior to the closing date, for federal income tax purposes the seller will be deemed to have received a payment from the purchaser in exchange for this production.69 Therefore, if the purchaser pays $1,000 (1) for the property and (2) for production totaling $100 during the period from the effective date to the closing date, then the purchase price for the seller’s relinquished property is only $900. If the seller identified more than $1,800 ($900 x 200 percent) of potential replacement properties, the seller may have over-identified its replacement properties.

One more important point. As discussed in §12.02[2] above, the creation of a lease or a sublease does not effect an exchange for federal income tax purposes. For the same reasons that the cash paid for a lease or a sublease is

65 Rev. Rul. 75-292, 1975-2 C.B. 333.66 Treas. Reg. § 1.1031(k)-1(c)(2)(ii).67 Id. § 1.1031(k)-1(c)(4).68 Id. § 1.1031(k)-1(c)(4)(ii).69 I.R.S. Tech. Adv. Mem. 8718003 (January 7, 1987).

§ 12.03


432

characterized as a lease bonus, the seller’s retention of a non-operating interest that is co-terminous with the lease (e.g., a royalty interest) does not create nor convey a property interest that may be the subject of an exchange.70 The conveyance is not characterized as a sale or exchange. On the other hand, the conveyance of an undivided interest in a lease with no retention of a non-operating interest is the proper subject of a like-kind exchange.

A “reverse exchange” or “parking arrangement” is also permitted. The seller may first contract to acquire the replacement property and have an exchange accommodation titleholder (“EAT”) actually hold the replacement property which may be used to replace a relinquished property that is identified by seller within 45 days after the acquisition of the replacement property. The EAT may hold the purported replacement property for 180 days after its acquisition.71 A person may qualify to function as an EAT if the person is not the taxpayer or a disqualified person.72 An EAT must be subject to federal income tax.73 Further, the seller must have a bona fide intent that the property held by the EAT represent replacement property in an exchange intended to qualify as a like-kind exchange.74 The seller and the EAT must enter into a written agreement confirming that the EAT is holding the replacement property for the benefit of the seller to facilitate a like-kind exchange, that the seller and EAT agree to follow the reporting requirements of Rev. Proc. 2000-37, and that the EAT be treated as the beneficial owner of the replacement property for federal income tax purposes.75 Rev. Proc. 2000-37 essentially allows the seller to deal with the EAT as if the seller owned the replacement property. The seller can advance funds to the EAT, indemnify the EAT against operating costs, cause the EAT to lease the property to seller, manage the replacement property, develop the property,

70 Crooks v. Comm’r, 92 T.C. 816.71 Rev. Proc. 2000-37, 2000-2 C.B. 308, § 4.02(5).72 See discussion at 12.03[2]; Treas. Reg. § 1.1031(k)-1.73 Rev. Proc. 2000-37, § 4.02(1).74 Id. 2000-37, § 4.02(2).75 Id. 2000-37, § 4.02(3).

§ 12.03


433

and enter into contracts relating to the purchase and sale of the replacement property.76

[3] — “Held For” Requirement.The requirement that the relinquished and the replacement properties

be held for use in a trade or business or for investment should be relatively easy to satisfy. However, the taxpayer should be mindful that the IRS has taken the position in the past that the withdrawal of the relinquished property from a controlled entity prior to the exchange77 and the contribution of the replacement property to a controlled entity following the exchange78 meant the withdrawn and contributed properties were not “held by” the taxpayer. The courts have not supported the IRS in these views.79

[4] — “Like-Kind” Requirement.The “like kind” rules are also relatively easy to satisfy because an oil and

gas property is considered to be real property for purposes of Section 1031 of the Code.80 The complicated asset class rules that are applicable only to the personal property assets therefore do not apply.81 Oil and gas properties may therefore be exchanged for a commercial office building or a multi-family apartment property.82 However, a domestic oil and gas property and a foreign oil and gas property are not considered to be like-kind.83

76 Id. 2000-37, § 4.03.77 Rev. Rul. 77-337, 1977-2 C.B. 305.78 Rev. Rul. 75-292, 1975-2 C.B. 333.79 Magneson v. Comm’r, 81 T.C. 767 (1983), aff’d, 753 F.2d 1490 (9th Cir. 1985) (exchange followed by drop-down did not violate the “held for” requirement), and Bolker v. Comm’r, 81 T.C. 782 (1983), aff’d, 760 F.2d 1039 (9th Cir. 1985) (Section 333 liquidation of wholly owned corporation and exchange of the distributed assets satisfies the “held for” requirement).80 Rev. Rul. 68-226, 1968-1 C.B. 362. The personal property features of the lease (e.g., lease and well equipment) may be a part of the real estate interests or may be separate personal property that are part of a separate exchange group for purposes of determining their like-kind status. Treas. Reg. § 1.1031(j)-1.81 Treas. Reg. § 1.1031(a)-2; (j)-1.82 Comm’r v. Crichton, 122 F.2d 181 (5th Cir. 1941); Rev. Rul. 68-331, 1968-1 C.B. 352. 83 I.R.C. § 1031(h)(1).

§ 12.03


434

[5] — Withdrawal of Properties from a Tax Partnership.As discussed above at §12.01[3], the undivided interests in oil and gas

properties are considered to constitute a partnership for federal income tax purposes even though title to the properties is held by the parties. This partnership status is largely elective for the parties, however, in that they may “elect out” of Subchapter K in most cases.

Because partnership interests (including interests in a tax partnership) are not eligible for like-kind exchange treatment, the participants must first “free” the oil and gas properties from the shackles of the tax partnership before engaging in the like-kind exchange. The “election out” effects a distribution of the oil and gas property to the participants.

Subchapter K has its benefits, but it also has land mines buried just below the surface. While the distribution of a property by a partnership is usually tax-free to the partners,84 the parties can recognize gain upon the distribution of properties that were deemed contributed to the tax partnership less than seven years prior to the deemed distribution of the properties.

[6] — Section 704(c)(1)(B).If a partner contributes built-in gain property to a partnership, the

contributing partner will recognize gain if the partnership distributes the built-in gain property to another partner within seven years after the contribution.85 The gain recognized is the amount of gain that would be recognized by the contributing partner under Section 704(c) of the Code if the partnership had instead sold the distributed property for its fair market value.86 Generally, the gain recognition amount would be limited to the built-in gain in the contributed property at the time of the formation of the tax partnership.

There are some important and meaningful exceptions. First, there is no gain recognition for the contributing partner if

84 Id. § 731.85 Id. § 704(c)(1)(B).86 Id.

§ 12.03


435

• the property contributed by the contributing partner is distributed to the contributing partner and to the other partners in liquidation of the partnership,

• no other property is distributed to the contributing partner, and

• the built-in gain in the property interest distributed to the contributing partner (determined at the time of the distribution) is not less than the built-in gain in the property that the contributing partner would have recognized if the built-in gain asset had been sold on the distribution date.87

The “election out” will generally qualify as a complete liquidation of the tax partnership for purposes of this rule.

[7] — Section 737.Section 737 of the Code adds an additional and more formidable

restriction. Section 737 provides that if a partner contributes built-in gain property to a partnership, the contributing partner will recognize gain if the partnership distributes other property to the contributing partner within seven years after the contribution.88

The gain recognized by the contributing partner is the lesser of (1) the built-in gain in the contributed property at the time of the distribution and (2) the excess of the fair market value of the distributed property over the distributee partner’s tax basis in its partnership interest.89

Unlike Section 704(c)(1)(B), there is no complete liquidation exception.

[8] — Examples.[a] — Tax Partnership — Example 1.

X contributes appreciated properties to a tax partnership and Y contributes cash to develop the properties. The tax partnership does not acquire any other properties. In order for Y to effect a like-kind exchange, X

87 Treas. Reg. § 1.704-4(c)(2).88 I.R.C.§ 737.89 Id.

§ 12.03


436

and Y elect out of Subchapter K and each is deemed to receive an undivided interest in the properties.

X does not recognize gain under Section 704(c)(1)(B) of the Code because the election out is treated as a complete liquidation of partnership.

X does not recognize gain under Section 737 of the Code because X, the contributing partner, receives an interest in the property contributed by the contributing partner. No other property is owned by the partnership and therefore no other property is deemed distributed to the partners.

[b] — Tax Partnership — Example 2.X contributes appreciated properties to a tax partnership and Y

contributes cash to develop the properties. X and Y also acquire additional properties that are considered assets of the tax partnership. X and Y later elect out of Subchapter K under Section 761, effectively terminating the tax partnership arrangement.

Result:

• X may not avoid gain under Section 704(c)(1)(B) of the Code because the complete liquidation exception does not apply — other properties are received by X.

• The distribution to X of the additional purchased properties will cause X to recognize gain under Section 737 of the Code.

§ 12.03


437

[c] — Tax Partnership — Example 3.X contributes appreciated properties to a tax partnership and Y

contributes cash to develop the properties. The tax partnership also acquires additional properties. Y desires to dispose of its share of certain properties (but not all properties) in a like-kind exchange, and the parties release the properties to be sold from the tax partnership agreement — effecting an in-kind distribution to each of the partners.

Situation 1. If the distributed properties were those originally contributed by X, X recognizes gain under Section 704(c)(1)(B) of the Code for the built-in gain in the properties deemed distributed to Y. The complete liquidation rule does not apply.

Situation 2. If the distributed properties were the acquired properties, X recognizes gain under Section 737 of the Code to the extent of the built-in gain in the contributed properties.

§ 12.03


438

Situation 1

Situation 2

§ 12.03


439

§ 12.04. Recent Developments in Upstream Master Limited Partnerships (MLPs) and Royalty Trusts.

In order to monetize producing oil and gas properties in a transaction that benefits from the public company multiples, some sponsors have recently used royalty trusts to dispose of their properties. These royalty trusts take many different forms and in some cases are characterized as a partnership for tax purposes, and, in other cases, they are treated as trusts for tax purposes.

[1] — Upstream Royalty Trust Taxed as Partnership.In 2011, SandRidge Energy, Inc. sponsored SandRidge Mississippian

Trust I, as a royalty trust.90 The SandRidge royalty trust had the following indicative terms:

• Formed to own and acquire producing and development oil and gas properties in Oklahoma

• The terms of the trust established a Target Distribution for each year based on the expected production (based on the reserve report) and the expected prices (based on approximately three years of the forward prices for the production followed by two and one-half percent per annum escalation thereafter)

• The Sponsor holds Incentive Distribution Rights which entitle the Sponsor to a special distribution equal to 50 percent of distributions in excess of 120 percent of the Target Distribution for the quarter

• Subordinated units held by the Sponsor do not participate in distributions if common units receive less than 80 percent of the Target Distribution for the Quarter

• The Sponsor had contracted for a drilling commitment for 123 PUD wells on the royalty trust properties by December 2014

• The Subordination period expires four quarters after completion of drilling commitment

90 SandRidge Mississippian Trust I is just one example of the publicly traded royalty trusts that have similar economic terms and structures.

§ 12.04


440

• The royalty trust is characterized as a publicly traded partnership for federal income tax purposes

[2] — Royalty Trusts — Trust for Tax.In order for a royalty trust to be characterized as a trust for tax purposes,

the trustee of the trust must have no power to vary the investment of the holders of the interests in the trust assets and there may only be a single class of interests in the trust.91 Practically speaking, in order for a royalty trust to be a trust for tax purposes, the sponsor must not hold any incentive distribution rights or subordinated equity interests that would be characterized as a second class of equity interest in the trust. The sponsor/trustee must have no authority to reinvest the earnings of the trust, to acquire other assets for the trust after formation, or to develop the assets of the trust.

A royalty trust that is treated as a trust for federal income tax purposes may not develop the properties, but the trust may indirectly bear the cost of development through a net profits interest royalty that deducts the costs of development (incurred directly by the sponsor) in determining the economic benefits to the holder. A royalty interest may not directly bear any costs of operation or development, but it may have its income rights reduced for those costs incurred by the working interest holders.92

Some recent examples of royalty trusts that are taxable as trusts for federal income tax purposes are:

• VOC Energy Trust (May 2011)

• Enduro Royalty Trust (November 2011)

[3] — Royalty Trusts — Partnership for Tax.A royalty trust whose business model does not permit it to observe the

“trust for tax” restrictions described above will be treated as a partnership for federal income tax purposes.93 A partnership that is publicly traded is

91 Treas. Reg. § 301.7701-4(c)(1).92 Kirby Petrol. Co. v. Comm’r, 326 U.S. 599 (1946).93 Treas. Reg. § 301.7701-4(c)(1); -2(a).

§ 12.04


441

generally taxable as a corporation,94 unless the partnership derives 90 percent or more of its income each year from interest, dividends, certain real property rents, gain from the sale of real property, income from natural resources, and gain from the sale of any property that generates these types of income.95 A royalty trust’s oil and gas income would clearly fall within the definition of income from natural resources which provides:

(E) income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy, and timber), industrial source carbon dioxide, or the transportation or storage of any fuel described in subsection (b), (c), (d), or (e) of section 6426, or any alcohol fuel defined in section 6426(b)(4)(A) or any biodiesel fuel as defined in section 40A(d)(1).96

Because the income of a royalty trust is exclusively derived from the production and sale of mineral and natural resources, a royalty trust easily avoids being treated as a corporation for federal income tax purposes.

Most royalty trusts choose the less restrictive approach and opt to be characterized as partnerships that qualify for the publicly traded partnership exception. Using the partnership structure, the sponsor may hold incentive units, may bear a disproportionate share of downside risk by holding subordinated units, and may reinvest earnings of the royalty trust. Some recent examples of royalty trusts using the partnership structure:

• SandRidge Mississippian Trust I (April 2011)• SandRidge Mississippian Trust II (April 2012)• ECA Marcellus Trust I (April 2011)• SandRidge Permian Trust (August 2011)• Chesapeake Granite Wash Trust (November 2011)

94 I.R.C. § 7704(a).95 Id. § 7704(d)(1).96 I.R.C. 7704(d)(1)(E).

§ 12.04


442

[4] — Types of Conveyances.[a] — Types of Properties.

A sponsor typically carves out a non-operating interest from its existing leases and conveys that non-operating interest to the royalty trust. The non-operating interest may be an overriding royalty interest that does not bear any operating or development costs or it may be a net profits royalty interest that bears operating costs or development costs or both by having those costs withheld from the economic cash flow of the holder.97

A sponsor may also convey to the royalty trust a non-operating interest that is perpetual98 or a term royalty that has an expected productive life that is less than the life of the lease.99

[b] — Tax Characteristics.The tax consequence to the royalty trust that holds a perpetual royalty

or perpetual net profit royalty is that the trust holders receive ordinary royalty income subject to depletion. The income attributable to the royalty is excludable from the sponsor’s income. The sponsor recognizes Section 1231 gain or loss from the sale of the carved out royalty interest.100

In the case of a term royalty or a term net profits interest that is carved out of the sponsor’s existing oil and gas leases, the interest is generally treated as though the royalty trust made a loan of cash to the sponsor secured by the production payment granted by the sponsor to the royalty trust.101

In the case of a carved out production payment conveyed for cash, the production payment is treated as a contingent payment debt instrument whose tax consequences are covered by the noncontingent bond method of the original issue discount regulations.102 Under these rules, the royalty

97 Kirby Petrol. Co. v. Comm’r, 326 U.S. 599 (1946); Rev. Rul. 73-541, 1973-2 C.B. 206.98 However, the sponsor will typically retain the option to repurchase the perpetual royalty interest held by the royalty trust for fair market value at the termination of the royalty trust.99 Typically, the term royalty terminates at a date certain (e.g., 20 years after its creation).100 Ratliff v. Comm’r, 36 B.T.A. 762 (1937). If the royalty trust is a partnership for federal income tax purposes, the sponsor may take advantage of the disguised sale rule and its exceptions in reporting gain from the transfer of the royalty interest to the royalty trust. See discussion at § 12.01[4], supra.101 Treas. Reg. § 1.636-1(a)(1)(i).102 Id. § 1.1275-4(b).

§ 12.04


443

trust will accrue interest income at the sponsor’s usual borrowing rate for its regular fixed rate, noncontingent indebtedness (its “comparable yield”).103 The sponsor will create a projected payment schedule over the term of the term royalty that will project the expected payments to be made to the royalty trust and the expected timing of those payments. The projected payment schedule must show that the holder is expected to receive an amount equal to its capital investment plus a return equal to the comparable yield.104 If in any year the amount actually received by the holder exceeds the projected payment for the year, the excess is included as additional interest income of the royalty trust and an interest deduction by the sponsor.105 If in any year the amount received is less than the projected payment for the year, the deficiency first reduces the interest income that the royalty trust would otherwise include for that year, then it will be treated as an ordinary loss in that year to the extent of the amount of any prior interest income inclusion by the holder and then is carried forward to offset the holder’s future interest income inclusions.106

Because royalty income (for a perpetual royalty) and interest income (for a term royalty) are exempt from the unrelated business taxable income definition,107 tax-exempt investors may invest in a royalty trust without unrelated business taxable income consequences so long as the tax-exempt investor and the royalty trust do not incur or assume indebtedness that was incurred to fund the purchase or development of the royalty trust’s assets or the equity interests in the royalty trust.108

103 Id. § 1.1275-4(b)(3)(i).104 Id. § 1.1275-4(b)(3)(ii). A projected payment schedule prepared by the sponsor will be controlling for the issuer and the holder so long as the projected payment schedule shows that the holder will receive its return of capital plus a return thereon at the comparable yield (unless the holder believes the schedule is unreasonable and submits its own schedule). Treas. Reg. § 1.1275-4(b)(4)(ii)(C); -4(b)(4)(iv).105 Treas. Reg. § 1.1275-4(b)(6)(ii).106 Id. § 1.1275-4(b)(6)(iii). The issuer/sponsor has mirror image treatment: The net negative adjustment first reduces the current year interest deduction, then causes the issuer to recognize income to the extent of the holder’s ordinary loss from the reversal of prior year interest inclusions, and then the carryforward reduces the issuer/sponsor’s interest deductions in the carryforward years.107 I.R.C. §§ 512(b)(1)-(2).108 I.R.C. §§ 512(b)(4), 514.

§ 12.04

cite as energy & min. l. inst. chapter 12 tax issues in the disposition of oil & gas...

Documents