Friday, March 30, 2018
The increased production of oil and gas on privately owned property in recent years means that an increasing number of landowners are receiving payments from oil and gas companies. It is important to understand the various types of payments that a landowner might receive and the tax consequences that may apply due to the nature of the income received.
Sorting through the various types of payments associated with an oil and gas lease and their tax implications is the topic of today’s post.
Relationship of the Parties
The income from the oil and gas property is commonly divided between the mineral interest owner (the royalty owner) and the operator (the working interest owner). In the typical lease arrangement, the royalty owner retains one-eighth (12.5 percent) and the working interest owner holds the other 87.5 percent (the balance of the portion of production or income that remains after the royalty interest owner’s share is satisfied).
The working interest owner bears the entire cost of exploration for minerals, as well as the development and production costs. The royalty owner bears none of the exploration, development, or operational costs. The funding necessary for the working interest owner to develop the oil and gas property is provided by investors who receive an interest in the activity in exchange for their capital investment. The costs of the activity borne by the working interest owner are allocated to the investors. These include geological survey costs, tangible costs (the drilling equipment and well), and intangible drilling costs (IDC). These costs can be currently deducted rather than capitalized.
This relationship between the working interest owner and the investors is typically a joint venture that is classified as a partnership for tax purposes. Thus, the partnership passes through the costs separately to the investors on Schedule K-1, Partner’s Share of Income, Deductions, Credits, etc. In the early years of the activity, the partnership typically passes through large losses to the partners. Because the partners are merely investors in the activity, the losses in their hands are passive losses. These losses are limited under the passive loss rules (I.R.C. §1411) such that they are only deductible to the extent the investor has passive income.
The working interest owner (who owns the interest either directly or through an entity that does not limit liability for the interest), however, is treated as being engaged in a non-passive activity regardless of the participation of the working interest owner. Temp. Treas. Reg. §1.469-1T(e)(4)(i). Likewise, for an investor who holds both a general and limited partnership interest, the investor’s entire interest in each well drilled under the working interest is treated as an interest in a non-passive activity regardless of whether the investor is materially participating.
Note: Investors in the working interest activity, given the broad definition of “partnership” contained in the Code, will likely have income from the activity that is subject to self-employment tax even though they are not materially participating in the activity. See, e.g., Methvin v. Comm’r, T.C. Memo 2015-81, aff’d., 653 Fed. Appx. 616 (10th Cir. 2016).
Types of Payments
Bonus payment. The lessee typically pays a lump-sum cash bonus during the initial lease term (pre-drilling) for the rights to acquire an economic interest in the minerals. This is the basic consideration that the lessee pays to the lessor when the lease is executed. The lessor reports the bonus payment on Schedule E, Supplemental Income and Loss. It constitutes net investment income (NII) that is potentially subject to the additional 3.8 percent NII tax (NIIT) of I.R.C. §1411. A bonus payment is ordinary income and not capital gain because it is not tied to production. See, e.g., Dudek v. Comr., T.C. Memo. 2013-272, aff’d., 588 Fed. Appx. 199 (3d Cir. 2014).
For the lessee, a bonus payment is not deductible even if it is paid in installments. It must be capitalized as a leasehold acquisition cost. However, the bonus payment may be subject to cost depletion.
Installment bonus payments. A bonus payment may be paid annually for a fixed number of years regardless of production. If the lessee cannot avoid the payments by terminating the lease, the payments are termed a lease bonus payable in installments. These payments are also consideration for granting a lease. They are an advance payment for oil, and each installment is typically larger than a normal delay rental.
A cash-basis lessee must capitalize such payments, and the fair market value (FMV) of the contract in the year the lease is executed is ordinary income to the lessor if the right to the income is transferable. Rev. Rul. 68-606, 1968-2 CB 42. However, if the bonus payments are made under a contract that is nontransferable and nonnegotiable, a cash-basis lessor can defer recognizing the payments until they are received. See, e.g., Kleberg v. Comm’r, 43 BTA 277 (1941), non. acq. 1952-1 CB 5.
Delay rentals. A delay rental is paid for the privilege of deferring development of the property by extending the primary term to allow additional time for drilling operations to begin. It can be avoided either by abandonment of the lease or by starting development operations (i.e., drilling for oil or obtaining production). A delay rental payment is “pure rent.” It is simply a payment to defer development rather than a payment for oil.
Delay rentals are ordinary income regardless of whether they are based on production. However, if they are not based on production, they are not depletable gross income to the lessor. Treas. Reg. §1.612-3(c)(2). Depletable gross income for the lessor is the royalty income received. Royalty income is based on production. If the delay rentals paid are not based on production, they do not reduce the lessee’s depletable gross income. Treas. Reg. §1.613-2(c)(5).
Delay rental payments are reported in the same manner as bonus payments. They are reported to the lessor in box 1 of Form 1099-MISC and constitute NII potentially subject to the additional 3.8 percent NIIT. The lessor reports the payments on Schedule E, with the amount flowing to line 17 of Form 1040, and are potentially subject to the NIIT.
Under Treas. Reg. §1.612-3(c), delay rentals are in the nature of rent that the lessee can deduct as a current expense. However, the IRS maintains that I.R.C. §263A applies to delay rentals, which requires that the payments be capitalized. The only exception to capitalization applies if the taxpayer has credible evidence establishing that the leasehold was acquired for some reason other than development.
Royalty income. A landowner royalty is the right to the oil, gas, or minerals “in place” that entitles the owner to a specified percentage of gross production (if and when production occurs) free of the expenses of development and operations. A royalty interest is a continuing non-operating interest in oil and gas. Thus, a royalty payment is a payment for oil and gas.
Royalty payments are payments received for the extraction of minerals from the property that the landowner, as lessor, owns. Royalties are paid as an agreed-upon percentage of the resource extracted (i.e., based on production).
Royalty payments are ordinary income that is reported to the lessor in box 2 of Form 1099-MISC. Royalty payments may be reduced by percentage or cost depletion. The lessor reports the royalty income on Schedule E, are they are included in NII and are subject to the additional 3.8 percent NIIT if the taxpayer’s gross income is above the applicable threshold ($200,000 single; $250,000 MFJ).
The lessee can deduct royalty payments as a trade or business expense. In addition, if the lessee pays the ad valorem taxes (taxes based on the property’s value) on mineral property, the payment constitutes an additional royalty to the lessor to the extent that income from production covers the tax payment.
Advance royalties. Although it is not commonly included in oil and gas leases, the lease may contain a provision providing the mineral owner with an advance royalty of the operating interest. Thus, an advance royalty is paid before the production of minerals occurs, and can be paid to the lessor either in a lump sum or periodically until production begins. The lessee deducts the advance royalty payments in the year in which the mineral production (on account of which it was paid) is sold.
Advance royalties are ordinary income to the lessor, and the lessor is not entitled to percentage depletion on the payments. However, the lessor is entitled to cost depletion in the year the payments are made to the extent they exceed production.
Advance minimum royalties. Advance minimum royalties meet the same conditions as an advanced royalty, but there is also a minimum royalty provision in the contract. This provision requires that a substantially uniform amount of royalties be paid at least annually over the life of the lease or for a period of at least 20 years.
The tax treatment to the lessor for advance minimum royalties is the same as with advanced royalties. The lessee can deduct the advance royalties from gross income in the year the oil or gas is sold or recovered. The lessee also has the option to deduct the payments in the year they are paid or accrued.
Shut-in royalties. The lease may provide for payments to be made to the lessor when a well is shut- in (turned off because of lack of market or marketing facilities) but the well is still capable of producing in commercial quantities. The lessee is entitled to deduct the shut-in royalty payment and the lessor must report the payment as income.
Damage payments. When a well is drilled, the nearby surface area can suffer damages that may entitle the landowner to compensation. To determine the income tax consequences of any payment for surface damages, the governing instrument (lease, etc.) may provide guidance.
Compensatory damages associated with lost profit (e.g., crop damage payments) are taxable as ordinary income (treated as a sale of the crop). To the extent the damage payment represents damages for destruction of business goodwill, the payment is nontaxable up to the taxpayer’s basis in the affected property. The amount of the damage payment that exceeds the taxpayer’s basis is taxable as I.R.C. §1231 gain. Payments for anticipated damages (but when no actual damage occurs) are reported as ordinary income. See, e.g., Gilbertz v. U.S., 808 F.2d 1374 (10th Cir. 1987), rev’g 574 F. Supp. 177 (Wyo. 1983).
Production payments. Most landowners retain only a royalty interest in minerals. However, landowners who have a working (operating) interest in the production may also receive a “production payment.” A production payment arises from a transaction in which the owner of an oil and gas interest sells a specific volume of production from an identifiable property until a specified amount of money or minerals has been received. A production payment is payable only out of the working interests’ share of production.
There are two types of production payments. Retained production payments result when the mineral interest owner assigns the interest and retains a production payment. The payment is payable out of future production from the assigned property interest. A carved-out production payment is created when an owner of a mineral interest assigns a production payment to another person but retains the interest in the property from which the production payment is assigned.
Generally, a carved-out production payment is treated under I.R.C. §636 as a mortgage (nonrecourse) loan on the property. As such, it does not qualify as an economic interest in the property. The lessee treats the payments as principal repayment and interest expense, and the lessor treats the payments received as principal and interest income. Thus, the producer does not recognize taxable income at the time the transaction is entered into. The lessor continues to be treated as the owner of the burdened properties. As the production occurs and is delivered to the holder of the production payment, the lessor is treated as having sold the production for its FMV and having applied the proceeds to repay the principal and interest due to the holder.
However, if the consideration given for the production payment is pledged for development of the property or if the production payment is retained when the property is leased, the payment qualifies as an economic interest. In this situation, the payments that the lessor receives via the production payment agreement are ordinary income that are subject to cost or percentage depletion. The lessee capitalizes the payments. The transaction may be treated as the sale of an overriding royalty interest in some instances, however.
Treas. Reg. §1.636-3 requires that the life of the production payment be shorter than the life of the property. Thus, for an unexplored property, if no minerals are discovered or the reserves are in such small quantities that they will never pay off the production payment, the production payment’s life will exist until the lease is abandoned. Once the lease is abandoned, the transaction is treated by the lessee as a purchase of an overriding royalty interest. It is capitalized by the lessee and treated as capital gain by the lessor.
Payments for “shooting rights.” In some situations, an operator may not want to incur the costs of entering into a lease on the property (to avoid lease bonuses, for example). Consequently, the operator may enter into a contract with the landowner to pay a smaller amount under a contract that gives the operator a right to enter onto the property to conduct exploration activities. The contract does not grant any drilling or production rights. The payments that the landowner receives under this type of arrangement are reportable as ordinary income.
Sorting out the proper tax treatment of various payments associated with an oil and gas lease is important and can be somewhat complex. For those receiving (or paying) such amounts, competent tax counsel should be consulted to ensure proper reporting. Today's post was just a quick summary of some of the tax issues associated with oil and gas production.