Maintenance of the Property
The ability to manage and maintain mineral interests is generally vested in the manager (if the vehicle selected is a state law limited liability company) or the general partner (if the vehicle selected is a state law limited partnership). The operating agreement or limited partnership agreement, as applicable, of the selected ownership vehicle contains management and succession provisions providing for what types of decisions the manager or general partner, as the case may be, is eligible to make (generally the manager or general partner makes all of the day-to-day operational decisions) and provides a succession plan so that certain designated persons will be appointed to serve in this decision-making capacity after the original transferor is no longer involved with the partnership (for example, because of death, disability, or resignation).
Maintaining the Ownership of the Property
When mineral interests are placed in a tax partnership, the transferors can retain the ability to transfer indirect ownership interests in oil and gas investments to family members without fractionalizing the ownership of these assets or affecting the continuity of the family’s oil and gas investment strategies. The terms of the partnership agreement (that is, the limited partnership agreement or limited liability company agreement, as the case may be) can be tailored to limit who can receive an interest in the partnership and, indirectly, an interest in the underlying minerals. Specifically, including the appropriate buy-sell terms in the operating agreement can enable the original transferor of the mineral interests to continue the ownership of the oil and gas investments within the transferor’s family lines and to restrict the right of nonfamily persons to acquire interests in the same.
Mineral interest owners generally have minimal liability exposure in connection with the production of oil or gas on the properties in which they have retained a royalty interest. In some cases, however, landowners choose to take part in the development of the mineral property through a working interest or some other form of economic interest, and, therefore, holding the mineral interest in a limited liability entity is prudent. In addition, placing the mineral interests in a tax partnership (that is, a limited liability entity) also can protect the mineral interests from liabilities arising out of the transferor’s individual circumstances.
Key Provisions in the Partnership Agreement
Generally, the property held inside the partnership will be subject to some form of ad valorem taxes and other operating expenses and, as such, it may be necessary to include a provision in the provisions of the operating agreement dealing with capital contributions requiring the members or partners to contribute additional capital to the partnership as needed to fund these expenses. The need for additional funding is likely necessary only in the early years of the partnership when the property is being developed because sufficient income may not be generated by the production activities to cover these expenses. But, as the minerals begin being produced (or in the case in which mineral production is used to fund the partnership initially), this need becomes less of an issue.
In the event the manager or general partner of the partnership does not intend to distribute all of the cash generated by the mineral interests in the partnership to the partners or members, often a provision in the operating agreement provides for distributions of cash to the partners or members to subsidize the tax burden borne by the partners or members as a result of their ownership interests in the partnership. The need for such a provision is most important when the intent of the partnership is to reinvest the proceeds from the production of the mineral interest in other investments.
Including a management succession provision in the operating agreement of the limited liability company agreement or limited partnership agreement for the entity housing mineral interests gives the original transferor the ability to determine at the outset the governance of the mineral interests. Generally, when the mineral interests are placed in a partnership and are intended to benefit the transferor’s family and future generations, the management succession provisions specify succession of the decision-making authority to be vested in the family lines of the transferor and his or her lineal descendants.
Buy-sell restrictions permit the original transferor of the mineral interests to the partnership to limit the ownership of the partnership to certain permitted transferees to further the estate planning goals of the transferor. Some of the more common types of buy-sell provisions are those dealing with the ability to transfer interests in the partnership to individuals of the original transferor’s family, to marital trusts and other types of trusts, to the estate of an owner of a partnership interest, and to charitable organizations. In addition, often included as buy-sell provisions in the relevant operating agreement are those provisions dealing with the divorce of a partner or member (that is, an individual) and the death of the spouse of a partner or member (that is, an individual).
Assignee vs. Substituted Member or Partner
The estate planning goals of owners of the partnership need to be carefully considered when determining whether a transferee of a partnership interest or membership interest is to be an assignee (that is, a partner or member with economic rights, but no voting rights) or a substituted member or partner (that is, a partner or member with economic rights and voting rights). If a transfer to a trust is anticipated, whether a transferee is considered an assignee or a substituted member or partner will affect the value placed on the assets transferred. That is, an assignee interest would likely be valued significantly lower than an interest received by a transferee in which the transferee is considered to be a substituted member or partner.
Income Taxation of Oil and Gas Partnerships
Oil and gas tax partnerships are an animal completely unlike any other, and they hold oil and gas property in a unique manner for tax purposes. The estate planner needs to avoid any missteps associated with the application of Subchapter K of the Internal Revenue Code to his or her client’s oil and gas family partnership.
Intangible Drilling Costs and Development Costs
In connection with the drilling of oil and gas wells, taxpayers that have a working or operating interest have the option either to expense or to capitalize intangible drilling and development costs (IDC). IRC § 263(c). Taxpayers that elect to have an immediate write-off in the year the IDC was incurred must make a binding one-time election with the IRS. The option to expense IDC applies to all amounts paid by an operator “for wages, fuel, repairs, hauling, supplies, etc. incident to and necessary for the drilling of wells and the preparation of wells for the production of oil and gas.” Treas. Reg. § 1.612-4(a). The election to immediately write-off IDC applies to those costs incurred to (1) drill, shoot, or clean a well, (2) clear the land and prepare the pad site for the drilling of wells (that is, ground clearing, surveying, road making, drainage, and geological works), and (3) construct derricks, tanks, pipelines, and other physical structures necessary for the drilling of wells and the preparation of wells for the production of oil and gas. Any costs expended on equipment that is normally considered to have a salvage value and is depreciable property is not allowed to be immediately deducted through the IDC election. The costs incurred by the taxpayer for this type of property can be recovered only through the depreciation allowance. Expenses that relate to the installation of production and treatment facilities are not considered to be an IDC. The expenses for operating wells or other facilities for the production of oil and gas are deductible as ordinary and necessary business expenses. The election to expense IDC is made by the partnership and not the individual partners.
The election to expense IDC is available only to the owner of a working or operating interest. Rev. Rul. 75-304, 1975-2 C.B. 94. As such, the owner of only a royalty interest will not be eligible to deduct expenses associated with the drilling of wells for the production of oil and gas because a royalty interest owner does not bear the costs of production and therefore will never benefit from the IDC. The issue that arises to the working interest owner who holds its working interest in a partnership form is whether the passive activity loss rules of IRC § 469 apply to limit the ability of the working interest owner to deduct IDC. IRC § 469 applies to limit the ability of a taxpayer to deduct losses from passive activities. A passive activity is any activity that involves the conduct of a trade or business and in which the taxpayer does not materially participate. Contained within the language of IRC § 469 is the working interest exception, which holds that “the term ‘passive activity’ shall not include any working interest in any oil and gas property which the taxpayer holds directly or through an entity which does not limit the liability of the taxpayer with respect to such interest.” IRC § 469(c)(3).
Because of the potential liability exposure associated with a working interest, most working interest owners hold their working interest indirectly through a limited liability entity (most notably the limited partnership or the limited liability company). The obvious rub for a working interest owner is weighing the benefits and burdens of the immediate IDC deductions versus the increased liability exposure to the working interest owner by holding the working interest directly or in an entity that does not limit liability (that is, the general partnership) to avoid the passive activity loss rules of IRC § 469. Careful attention should be used by the practitioner to properly discuss with his or her client that holds working interests the potential benefits and burdens of the IDC deduction and whether or not holding the working interest in a limited liability vehicle is the best option. The practitioner might find that holding the working interest outside of a limited liability vehicle coupled with the purchase of liability insurance (or liability insurance held by the operator in a joint venture) might best suit his or her client’s needs.
Basis of Oil and Gas Properties Held by Partnership
On the exchange of property held by a partner to a partnership in exchange for an interest in the partnership, the tax consequences resulting from such exchange are governed by Subchapter K of the IRC. Specifically, IRC § 721 states the general rule that no gain or loss is recognized to a partner on the contribution by such partner of property to the partnership in exchange for an interest in the partnership. The basis held by the partner in his or her partnership interest is equal to the adjusted basis of the property contributed to the partnership plus any gain recognized by the partner on the contribution. IRC § 722. Likewise, the basis of the property contributed by the partner to the partnership shall be equal to the adjusted basis of the property at the time of contribution plus any gain recognized by the contributing partner on the contribution. IRC § 723. In tax jargon, the basis determined under IRC § 722 is often referred to as the “outside basis” and the basis determined under IRC § 723 is often referred to as the “inside basis.” The determination of basis is critical in partnership tax to properly account for the operations of the partnership and to ensure that the flow-through income tax regime is maintained. In the normal case of depreciable property, the partnership computes the depreciation allowance applicable to the subject property and this amount flows through to the partners (based on the partners’ allocation scheme) to be applied on their individual tax returns, and then this amount will adjust the partners’ outside basis in the property.
When oil and gas property is held by a tax partnership, the inside basis of the property is held by the individual partners and not the partnership, so that each partner determines his depletion allowance. IRC § 613A(c)(7)(D). In determining each partner’s allocable share of basis in the oil and gas property held by the partnership, the partnership allocates to each partner his proportionate share of the adjusted basis of each oil and gas property. Each partner separately keeps records of his share of the adjusted basis in each oil and gas property of the partnership, adjusts the share of the adjusted basis for any depletion taken on the property (regardless of whether the partner takes cost depletion or percentage depletion), and uses such adjusted basis each year in computing his cost depletion for that year or his gain or loss on the disposition of such property by the partnership. In essence, a partner in an oil and gas partnership holds both the inside basis of the oil and gas property and the outside basis of the partnership interest. For partnerships that satisfy the substantial economic effect test of the regulations under IRC § 704(b), then the initial allocations of basis of the oil and gas property are made in accordance with the allocation scheme. If the allocations do not have substantial economic effect, the allocations of the basis of the oil and gas property among partners are governed exclusively by IRC § 613A(c)(7)(D) and the regulations thereunder, which provide that basis in an oil and gas property must be allocated in accordance with the partners’ interest in “capital” unless the partnership agreement provides that the allocation is made in accordance with the partners’ shares of “income,” and when the allocation is made each partner’s share of income is “reasonably expected to be substantially unchanged throughout the life of the partnership.” The default rule under IRC § 613A is that basis is allocated in accordance with each partner’s share of capital.
Because the basis of oil and gas properties is held outside of the partnership, special basis rules are included in IRC § 705 to make sure that a partner’s outside basis is properly adjusted to account for depletion taken by the partner under IRC § 611. It is important to note that IRC § 705 provides rules for dealing with depletion at the partnership level when the property is not oil and gas property. A practitioner will not want to confuse this with the treatment of depletion for oil and gas property. Except for oil and gas property, the partnership itself holds the basis of the mineral property and the calculations of depletion at the partnership level are included in a partner’s distributive share (either in the calculation of gain or loss for the year), and the partner’s outside basis is increased or decreased accordingly. IRC § 705(a)(1)(C) provides that the excess depletion deductions taken by the partnership over the adjusted basis of the property increases the partner’s outside basis. This is necessary to ensure that the depletion deductions are not lost on the partner because if there were no corresponding outside basis increase to the partner, then, on a sale by the partner of his or her partnership interest, gain would be recognized to the extent of the depletion deduction.
The aforementioned rule is not applicable to oil and gas partnerships because the basis of the property is held outside of the partnership, and the calculation of depletion is computed outside of the partnership context. As such, a special basis rule is included for oil and gas partnerships in IRC § 705(a)(3), which provides that a partner’s outside basis is to be decreased (not below zero) for depletion taken by the partner to the extent of basis in the oil and gas property. The result of this rule for oil and gas partnerships is to put the partners of an oil and gas partnership in the same tax position as other similarly situated partners in other mineral partnerships. This special basis rule is necessary because of the unique nature of oil and gas partnerships, which require the basis of the property to be held by the individual partners as opposed to the partnership.
Depletion of Oil and Gas Property: Cost vs. Percentage
The inside and outside basis rules discussed above for oil and gas properties held within a partnership structure were enacted in 1975 as part of Congress’s revisions of the oil and gas depletion rules. Until that time, any producer of oil and gas could claim a percentage depletion deduction, measured by the fixed percentage of the gross income from the property. During the early 1970s, when oil prices skyrocketed, many oil and gas companies were highlighted by the press as price gougers at the expense of the American public. The percentage depletion allowance was seen as an unnecessary governmental subsidy to this booming market segment. In response to public pressure, Congress was ready to move on new legislation that would have had the effect of denying percentage depletion to any oil and gas producer and instead would have required the producer to use the less-favored cost depletion. Cost depletion is computed generally in the following manner: cost of the mineral interest divided by the estimated recoverable reserves (which represents cost per unit) multiplied by the number of units sold during the tax year. Late in the legislative process, however, a compromise was struck in Congress that allowed certain producers the ability to use percentage depletion yet required others to use cost depletion.
IRC § 611 and the regulations thereto provide that there be allowed as a deduction in computing taxable income in the case of oil and gas properties a reasonable allowance for depletion, which shall be computed on either the adjusted depletion basis of the property (that is, cost depletion as determined under IRC § 612) or on a percentage of gross income from the property (that is, percentage depletion as determined under IRC § 613A), whichever results in the greater allowance for depletion for any taxable year. As such, an eligible taxpayer that can qualify for either method will determine annually which method provides him the greatest depletion allowance and use that method for the given tax year. Generally, the percentage depletion allowance is preferred by taxpayers because it is not limited to the taxpayer’s adjusted basis in the property and often yields the greater deduction amount. In practice, a taxpayer using the cost depletion method can take depletion adjustments for only so long as that taxpayer has a positive basis in the property, whereas a taxpayer can use the percentage depletion allowance even if the adjusted basis of the property has been reduced to zero. Normally, IRC § 704(d) limits the ability of the taxpayer to claim partnership deductions in excess of his basis in the partnership. Because depletion is claimed outside of the partnership, however, IRC § 704(d) is not applicable to the taxpayer. As such, the taxpayer may take depletion deductions in excess of the basis the taxpayer has in his partnership interest.
The compromise met by Congress in 1975 was to deny percentage depletion for integrated producers while allowing independent producers to continue to claim percentage depletion on a limited amount of annual domestic production. Percentage depletion is completely denied for any foreign oil and gas production. Under IRC § 613A(d), integrated producers are those producers that are engaged in refining oil and gas properties or engaged in the retailing of such products, subject to certain exceptions, as well as any company related to another company that is engaged in such operations. By inference, if a producer does not fit the definition of an integrated producer, then such producer would qualify as an independent producer. As a result of Congress’s legislative action in 1975, integrated oil and gas companies have been limited to cost depletion.
As a result of this new legislation, the hybrid partnership rules discussed above were adopted to ensure that integrated producers could not circumvent the direct application of IRC § 613A by instead holding the oil and gas property subject to depletion through a partnership as opposed to direct ownership. Congress recognized that in many cases oil and gas partnerships were important to the development of mineral properties, and as such limiting integrated producers from becoming partners with independent producers in oil and gas partnerships would be detrimental to the development of mineral properties. To balance the need to have integrated producers and independent producers as partners in a partnership and to restrict the ability of integrated producers to claim percentage depletion, Congress enacted IRC § 613A(c)(7)(D), discussed above, so that the depletion allowances are computed outside of the partnership. In a partnership between an integrated producer and an independent producer, the integrated producer would compute depletion on the cost method, and the independent producer would compute on the greater of the cost method or percentage method.
Recapture of Intangible Drilling Costs and Depletion (IRC § 1254)
Certain costs associated with oil and gas properties placed in service after 1986 are subject to recapture under IRC § 1254 on disposition. IDC and development costs are subject to recapture to the extent such costs would have been included in the adjusted basis of the property if they would have been capitalized instead of being immediately deducted by the taxpayer in the year the cost was incurred. IDC recapture under IRC § 1254(b) is to be determined under rules similar to the determination of depreciation recapture under IRC § 1245. Depletion is also subject to recapture under IRC § 1254. The amount of depletion recapture will be limited to the lesser of (1) the amount of depletion deductions taken by the taxpayer on the property that actually reduced the adjusted basis of the property or (2) the taxable gain on disposition. The result of the recapture provisions is to convert capital gain into ordinary income by accounting for the deductions taken by the taxpayer against previous ordinary income. As shown in the statutory language of IRC § 1254, percentage depletion is of much greater benefit to the taxpayer than cost depletion because, although both depletion methods reduce adjusted basis to zero, with percentage depletion any depletion deductions in excess of basis will not be subject to the recapture provisions of IRC § 1254.
For property placed into service before 1987, the amount recaptured is the lower of (1) the amounts deducted for IDC that exceed the amounts that would have been allowed had the IDC been capitalized or (2) the excess of gain realized from a sale or exchange over the adjusted basis of the property.
Application of IRC § 704(c) to Oil and Gas Partnerships
IRC § 704(c)(1)(A) provides that income, gain, loss, and deduction for property contributed by a partner to the partnership will be shared among the partners to take into account the difference between the property’s adjusted basis and its fair market value at the time of contribution. The purpose of this rule is to prevent the shifting of precontribution gains or losses among the partners. Treas. Reg. § 1.704-3(a)(1). IRC § 704 primarily applies to sales by a partnership of contributed property and depreciation and depletion for contributed property.
In making IRC § 704(c) allocations to resolve issues reflected in book/tax disparity, the regulations allow the partnership to use any reasonable method that is consistent with the purpose of IRC § 704(c). The regulations specifically authorize three methods: (1) the traditional method; (2) the traditional method with curative allocations; and (3) the remedial method. A partnership can use different allocation methods for different properties, but the method used for a specific property must be consistently used year to year. When the traditional method is applied, issues often arise as a result of the “ceiling rule.” The “ceiling rule” states that the total income, gain, loss, or deduction allocated to a partner for a taxable year for any IRC § 704(c) property may not exceed the total partnership income, gain, loss, or deduction for that property for the taxable year. The ceiling rule can have the effect of temporarily shifting precontribution gains among partners or limiting tax depreciation allocated to noncontributing partners. The traditional method with curative allocations and the remedial method aim to remedy the distortions caused by the application of the ceiling rule.
In the context of an oil and gas partnership, the application of IRC § 704(c) is more complicated because the basis of the oil and gas property is held outside of the partnership by the partners. In general, the rules of IRC § 704(c) apply in the same general manner as any other mineral partnership, but there are increased complexities and little statutory, regulatory, or administrative guidance because of the unique nature of oil and gas partnerships. Generally speaking when dealing with depreciation allowances, IRC § 704(c) seeks to remedy any precontribution gains of depreciable property by allocating more of the tax depreciation to the noncontributing partners so that the contributing partner over the remaining depreciable life of the property recognizes the precontribution gain in the form of additional taxable income each year because the contributing partner did not have the benefit of the larger depreciation deductions. The theory behind this shifting of the depreciation allowance to the noncontributing partners is that the property at the end of its depreciable life will be worthless so that the partnership will not be able to sell it and recognize the built-in gain at that time. As such, the contributing partner would not have to recognize his or her precontribution gain.
In the context of the application of IRC § 704(c) to oil and gas partnerships, the partners will be concerned primarily with the allocation of basis to the partners and the calculation of the depletion deductions, as allocations to cure book/tax disparity are determined based on how the partners determine to allocate basis on the contribution of the IRC § 704(c) oil and gas property to the partnership. This concept is especially important in an oil and gas partnership when one partner contributed the oil and gas property that is subject to IRC § 704(c) gain and the other partners are equity/cash partners. The equity/cash partners will want to structure the partnership so that they receive their proportionate share of the book depreciation on the oil and gas property. Because the property has a book/tax disparity on contribution, however, the depletion allowances will be affected by IRC § 704(c). Depending on the allocation method chosen, the annual tax effect to each partner could vary greatly based on the shifting of the depletion allowances. As a result of this shifting, the partner that contributed the IRC § 704(c) property could be required to recognize more taxable income in a given tax year because that partner would be allocated a smaller depletion allowance. The mechanics of the allocation methods are outside the scope of this article and could be the subject of a lengthy article all by themselves. The authors strongly recommend that the parties seek competent oil and gas tax professionals to advise on the transaction structure when dealing with the situation of a partner that is contributing IRC § 704(c) property to a partnership but the other partners are contributing non-IRC § 704(c) property. The choice of allocation method will be a key negotiating term that will need to be agreed to by the partners before entering into a partnership arrangement.
Because the partners in an oil and gas partnership hold the basis of the property outside of the partnership, the partners themselves will separately calculate the depletion and gain or loss for the partnership property. Because of the technical nature of oil and gas accounting for mineral partnerships, the accounting firm that represents the mineral partnership will more than likely perform a simulated depletion calculation on an asset-by-asset basis to provide to the partners, which will reflect the amount of cost or percentage depletion allowance available on each separate partnership property. The partners will in turn use this simulated depletion calculation to compute their individual depletion allowance (based on either the cost or percentage depletion method). In addition, when an oil and gas partnership disposes of the property, each partner is then required to compute the gain or loss on the property separately. These wrinkles require the partnership to communicate closely with the partners so that the partners can adequately determine the tax consequences arising from the ownership of the partnership interest. Specifically, the partnership will need to adequately communicate the gross income from the operations of the property so that each partner can determine the amount of depletion to take against his share of the property’s basis (note that gross income is necessary to compute percentage depletion, which is the depletion calculation method normally used by most taxpayers that are the subject of this article; however, if the taxpayer is forced to use cost depletion, the partnership will need to communicate information related to the amount of oil or gas produced and the amount of estimated reserves for the taxpayer to appropriately calculate his depletion deduction).
Having an advisor that is comfortable with the structure and taxation of oil and gas partnerships is important in assisting clients with their planning needs related to their mineral interests because complexities exist even in the simplest of estate plans (when a tax partnership is used). A mineral partnership operates like other partnerships, except that the practitioner needs to be aware that certain income tax nuances exist with mineral properties that make the income taxation of mineral partnerships more difficult than the taxation of nonmineral partnerships.