The Depletion Deduction For Oil and Gas Operations

Overview

Owner-lessors and operator-lessees of oil and gas interests can claim depletion associated with the production of oil and gas. Although conceptually similar to depreciation, the depletion deduction differs in significant ways from depreciation. The depletion deduction is based on the depletion of the mineral resource, whereas depreciation is based on the exhaustion of an asset that is used in the taxpayer’s trade or business.

The depletion deduction associated with oil and gas interests – that’s the topic of today’s post.

Requirements for the Deduction

To claim a depletion deduction, the taxpayer must have an economic interest in the mineral property, and the legal right to the income from the oil and gas extraction.  Treas Reg. §1.611-1(b).  If these two requirements are met, the deduction is allowed upon the sale of the oil and gas when income is reported.  For the owner-lessor, the deduction can offset royalty payments but not bonus lease payments (because the deduction is allowed only when oil or gas is actually sold and income is reportable).  For the operator-lessee, the depletable cost is the total amount paid to the lessor (the lease bonus) and other costs that are not currently deducted such as exploration and development costs as well as intangible drilling costs.

Conceptually, the taxpayer is entitled to a deduction against the revenue received as the income tax basis in the mineral property is depleted. For the owner-lessor, a cost basis in the minerals must have been established at the time basis in the taxpayer’s property (surface and mineral estate) was established. This may have occurred as part of an estate tax valuation in which the minerals and surface were separately valued or upon allocation of the purchase price at the time of acquisition. For the operator- lessee, the operator’s historical investment cost is the key.

When a lease of minerals is involved, the depletion deduction must be equitably apportioned between the lessor and the lessee.  IRC §611(b). If a life estate is involved (the property is held by one person for life with the remainder to another person), the deduction is allowed to the life tenant but not the remainderman. For property held in a trust, the deduction is apportioned between the income beneficiaries and the trustee in accordance with the terms of the trust. If the trust instrument does not contain such provisions, the deduction is apportioned on the basis of the trust income allocable to each. For a decedent’s estate, the deduction is apportioned between the estate and the heirs on the basis of the estate income allocable to each.

Computation Methods

There are two methods available for computing the depletion deduction: the cost depletion method and the percentage depletion method. A comparison should be made of the two methods and the one that provides the greater deduction should be used.

Cost depletion.  For the owner-lessor, the cost depletion method is a units-of-production approach that is associated with the owner’s basis in the property. Cost depletion, like depreciation, cannot exceed the taxpayer’s basis in the property. The basis includes the value of the land and any associated capital assets (e.g., timber, equipment, buildings, and oil and gas reserves).  See I.R.C. §612.     Basis also includes any other expenses that were incurred in acquiring the land (e.g., attorney fees, surveys, etc.).  Basis is tied to the manner in which a property is acquired.  For example, mineral property can be acquired via purchase (purchase price basis), inheritance (basis equals the property’s FMV at the time of the decedent’s death) or gift (carryover basis from the donor).  Basis is allocated among the various capital assets and is determined after accounting for the following items:

1. Amounts recovered through depreciation deductions, deferred expenses, and deductions other than depletions;

2. The residual value of land and improvements at the end of operations; and

3. The cost or value of land acquired for purposes other than mineral production

Under the cost depletion approach, the taxpayer must know the total recoverable mineral units in the property’s natural deposit and the number of mineral units sold during the tax year. The total recoverable units is the sum of the number of mineral units remaining at the end of the year plus the number of mineral units sold during the tax year.  The landowner must estimate or determine the recoverable units of mineral product using the current industry method and the most accurate and reliable information available.  A safe harbor can be elected to determine the recoverable units. Rev. Proc. 2004-19, 2004-10 IRB 563.  The mechanics of the computation are contained in Treas. Reg. §1.611-2.

The number of mineral units sold during the tax year depends on the accounting method that the taxpayer uses (i.e., cash or accrual). Many taxpayers, particularly landowners, are likely to be on the cash method. Thus, for these taxpayers, the units sold during the year are the units for which payment was received.  Under the cost depletion approach, an estimated cost per unit of the mineral resource is computed annually by dividing the unrecoverable depletable cost at the end of the year by the estimated remaining recoverable units at the beginning of the year. The cost per unit is then multiplied by the number of units sold during the year.

Let’s look at an example:

Billie Jo’s father died in 2014. His will devised a 640-acre tract of land to Billie Jo. The value of the tract as reported on Form 706, United States Estate (and Generation-Skipping Transfer) Tax Return, for estate tax purposes was $6.4 million. Of that amount, $1 million was allocated to the mineral rights in the tract.

In 2018, a well drilled on the property produced 300,000 barrels of oil. Geological and engineering studies determined that the deposit contained 2 million barrels of usable crude oil. In 2018, the 300,000 barrels produced were sold.  Billie Jo’s cost depletion deduction for 2018 is $150,000 and is calculated as follows.

Unrecoverable depletable cost at the end of the year                            ×                 Number of units Estimated remaining recoverable units at the beginning of the year           sold during the year

$1,000,000 /$2,000,000 ×  300,000 = $150,000 

Billie Jo deducts the $150,000 on her 2018 Schedule E. Billie Jo’s adjusted basis in the mineral deposit for 2019 that is eligible for cost depletion is $850,000 ($1 million − $150,000).

Also, consider this example:

Acme Drilling Corporation paid Bubba $300,000 to acquire all of the oil rights associated with Bubba’s land. The $300,000 was Acme’s only depletable cost. Geological and engineering studies estimated that the deposit contains 800,000 barrels of usable crude oil.

In 2018, 200,000 barrels of oil were produced and 180,000 were sold. Acme’s cost depletion deduction for 2015 is $67,500 and is calculated as follows.

Unrecoverable depletable cost at the end of the year                                 x              Number of units

Estimated remaining recoverable units at the beginning of the year                        sold during the year

$300,000 /$800,000 × 180,000 = $67,500 

Percentage depletion. As noted previously, the amount allowed as a depletion deduction is the

greater of cost or percentage depletion computed for each property (as defined in I.R.C. §614(a) for the tax year.  See IRC §§613 and 613A and Treas. Reg. §1.611-1(a).

Landowners without an established cost basis may be able to claim percentage depletion (discussed later). It is common for a landowner to not allocate any part of the property’s basis to the oil and gas reserves. Thus, percentage depletion may be the only depletion method available.

Under the percentage depletion method, the taxpayer (owner-lessor or a producer that is not a retailer or refiner) uses a percentage of gross income from the property, which is limited to the lesser of the following:

• 15% of the gross income from the oil/gas property (for an operator-lessee, this is defined as gross income from the property less expenses attributable to the property other than depletion and the production deduction, but including an allocation of general )

• 65% of the taxable income from all I.R.C. §613A(d).   

For percentage depletion purposes, total taxable income is a function of gross income. Gross income from the property includes, among other things, the amount received from the sale of the oil or gas in the immediate vicinity of the well.  Treas. Reg. §1.613-3. Gross income does not include lease bonuses, advance royalties, or other amounts payable without regard to production from the property.  I.R.C. §613A(d)(5).

Any amount not deductible due to the 65% limitation can be carried over to the following year, subject to the same limitation. Any amount carried over is added to the depletion allowance before any limits are applied for the carryover year. I.R.C. §613A and the underlying regulations set forth a detailed multi-step process that is utilized to compute percentage depletion allowed to independent producers and royalty owners.

A production limit also applies. For partnerships, all depletion is computed at the partner level and not by the partnership.  Prop. Treas. Reg. §1.613A-3(e).  The partnership must allocate the adjusted basis of its oil and gas properties to its partners in accordance with each partner’s interest in capital or income.

Consider the following example:

In 2018, Rusty received $50,000 of royalty income from a well on his farm. His taxable income from all sources in 2018 is $432,000. Of that amount, $300,000 is income from crops and livestock. He has $82,000 of income from other sources.

Rusty computes his percentage depletion deduction by multiplying his $50,000 gross income from the oil/gas property by 15%, which is $7,500.   His taxable income from all sources is $432,000, and 65% of that amount is $280,800. Thus, Rusty’s depletion deduction is the lesser of $7,500 or $280,800. Rusty can claim the $7,500 deduction on line 18 (depreciation expense or depletion) of his 2018 Schedule E.

Conclusion

Oil and gas taxation is complex.  But, the Code does provide some beneficial rules to offset the cost of production.  That’s true for other lines of businesses also.  The cost of production associated with business property typically generates a tax write-off.  When it comes to oil and gas, the rules may be more difficult.  If you have these issues, it will pay to hire tax counsel that is well versed in the tax rules associated with oil and gas.