Changes to Oil & Gas Taxation Under a New Administration

Thoughtware Article Published: Dec 28, 2020
Oil Fields


Oil and gas companies have faced many challenges over the past several years, from price fluctuations due to the ongoing crude oil inventory glut to regulatory changes from increased oversight and scrutiny from government agencies to funding challenges such as the reverberations from the rise of so-called “ESG”-conscious investing and lending. Given the current state of the U.S. presidential and senate elections, there now exists a significant possibility that changes will be made to certain “tax expenditures” in the U.S. Internal Revenue Code (IRC) for the “fossil fuel subsidies” that benefit oil and gas and, more specifically, exploration and production companies. “Tax expenditures” are defined under the Congressional Budget and Impoundment Control Act of 1974 as:

“… revenue losses attributable to provisions of the Federal tax laws which allow a special exclusion, exemption, or deduction from gross income or which provide a special credit, a preferential rate of tax, or a deferral of tax liability.”  

While there are several tax expenditures that are usually classified as “fossil fuel subsidies” (the Joint Committee on Taxation, for reference, lists 21 energy-related tax expenditures in its annual report), the two that are referred to most often are the optional deduction for “intangible drilling and development costs” (IDC) by operators in the development of oil and gas properties authorized by Section 263(c) and further defined under §1.612-4 and the deduction for percentage depletion by independent producers and royalty owners authorized by §613A. What follows is historical background, brief explanations of the mechanics, and the estimated dollar tax effects of a potential repeal of the deductions for IDC and percentage depletion.

Intangible Drilling & Development Costs

Those with a background in accounting should be familiar with the distinction between capital expenditures (sometimes called “CAPEX”), which are reported on the balance sheet, and operational expenditures (sometimes called “OPEX”), which are reported on the income statement. Under generally accepted accounting principles (GAAP), generally, expenditures with a future benefit extending beyond the balance sheet date, i.e., year-end, are capitalized, whereas those with no future benefit, i.e., those that only benefit the current period, are expensed. Under this framework, IDCs (defined below in an excerpt from §1.612-4) and tangible drilling costs are both typically capitalized under GAAP.

“… all expenditures made 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 or gas.”

The IRS’ Market Segment Specialization Program Oil and Gas Industry literature defines IDCs more specifically and festively, i.e., “underneath the Christmas tree,” as:

“… IDC are all costs which are the intangible or nonsalvageable costs of drilling up to and including the cost of installing the ‘Christmas tree.’ The term ‘Christmas tree’ refers to the pipes, valves, and fittings that are used to regulate the flow of oil and gas from the wellhead. Many times, the physical arrangement of these pipes and valves resemble a ‘Christmas tree.’”

The IRC rules for capitalizing versus deducting expenditures largely conform with the GAAP rules for capitalizing versus expensing (with some notable exceptions), but the IRC of 1954 established a specific carve-out (or “tax expenditure”) under §263(c) to allow taxpayers to elect to deduct their IDCs. Instead of defining IDCs under §263(c), however, the code section references future regulations regarding IDCs to be written by the IRS (of which eventually came §1.612-4). There have been several additional rules put in place regarding the deduction for IDCs in the 66 years since its first appearance in the IRC. We will briefly touch on some of those rules below.

  • Election to deduct IDCs:
    • A formal election isn’t required under §1.612-4(d) (though it’s a good practice nevertheless to include one). Instead, a taxpayer makes the “election” by deducting IDCs on the tax return for their first taxable year with IDCs
    • Taxpayers who fail to make an election must recover IDCs through depletion
  • “Major integrated oil companies”:
    • Defined under §167(h)(5) as producers of crude oil with average daily worldwide production of crude oil of at least 500,000 barrels and gross receipts in excess of $1,000,000,000
    • Required under §291(b) to capitalize 30 percent of their IDCs and amortize the amount over the 60-month (five-year) period beginning with the month in which the costs are paid or incurred  
  • Alternative minimum tax (AMT):
    • “Excess intangible drilling costs” as defined under §57(a)(2) are an element in the calculation of a tax preference, i.e., addback to AMTI, for AMT purposes
    • Calculation is complex and outside the scope of this article, but the tax preference item can significantly reduce the tax benefit of deducting IDCs
  • Foreign IDCs:
    • IDCs paid or incurred outside the U.S. must generally be capitalized and depleted (or amortized over 10 years if depletion doesn’t apply) under §263(i)
  • Additional election to amortize over 60 months
    • Available secondary election (to taxpayers who have already elected to deduct IDCs) under §59(e) to amortize IDCs over 60-month (five-year) period
    • Avoids the AMT tax preference typically associated with IDCs     

While it’s by no means certain that the deduction for IDCs will be on the proverbial “chopping block” under a new U.S. presidential administration and Congress, it has been one of the specific tax expenditures named in U.S. Democratic Party campaign literature as needing to be curtailed or repealed. In its latest “Estimates of Federal Tax Expenditures for Fiscal Years 2020-2024,” the Joint Committee on Taxation estimated the tax expenditure, i.e., the dollar cash tax benefit received by taxpayers, related to “expensing of exploration and development costs” (which includes the deduction for IDCs) to be $1.6 billion for corporations and $0.5 billion for individuals for tax years 2020 through 2024. If the deduction for IDCs were to be repealed, this increase in tax revenue could potentially fall the heaviest on smaller corporations, i.e., those that aren’t “major integrated oil producers,” due to how the mechanics of the deduction is calculated.  

Percentage Depletion

The even older IRC of 1939 established the oft-maligned deduction for taxpayers with mines, wells (including oil and gas wells), and other natural deposits called “percentage depletion” (also referred to as “statutory depletion”). A high-level summary of the calculation for percentage depletion under §613 (or §613A in the case of oil and gas wells) is below.

Percentage Depletion Formula

The IRC of 1939 also codified the deduction for cost depletion, which corresponds with how depletion expense is calculated under GAAP (and is sometimes called the “units of production method”). A high-level summary of the calculation for cost depletion under §611 is below.

Cost Depletion Formula

Under the current IRC, taxpayers with costs subject to recovery by depletion must calculate both cost depletion under §611 and percentage depletion under §613 (or §613A in the case of oil and gas wells) and deduct the higher of the two amounts calculated on a property-by-property basis. An example of this two-part calculation follows below. 

Cost Depletion ExamplePercentage Depletion Example

Taxpayers must reduce the adjusted basis in their depletable properties by their deductions for depletion for each property (but not below zero) whether they claim percentage depletion or cost depletion. Since percentage depletion can result in a deduction for depletion greater than a property’s adjusted basis, a taxpayer is theoretically able to claim a deduction even after they’ve recovered their initial investment in the property, i.e., a “free tax deduction.” This tax benefit has made percentage depletion a target for tax-happy U.S. legislators since it was originally established in 1939. For reference, in both the IRC of 1939 and the IRC of 1954, the statutory depletion percentage for oil and gas wells was originally as high as 27.5 percent. It has since been reduced to 15 percent. The taxable income limitation of 65 percent also was added by the Tax Reduction Act of 1975 and codified in the IRC of 1986. There have been several additional rules put in place regarding the deduction for percentage depletion in the 81 years since its first appearance in the IRC. We will briefly touch on some of those rules below.

  • “Depletable oil quantity”:
    • Taxpayers may only deduct percentage depletion on production up to their “depletable oil quantity” defined by §613A(3)
    • In general, the “depletable oil quantity” is 1,000 barrels of oil equivalent (BOE) per day (or 365,000 BOE per year)
  • Retailers and refiners limited:
    • Limitations on percentage depletion exist for retailers and refiners under §613A(d)(2) and §613A(d)(4), respectively
    • The limitations involved are complex and outside the scope of this article
  • AMT:
    • The amount of percentage depletion deducted in excess of a property’s adjusted basis is a “tax preference” for AMT purposes under §57(a)(1) (except in the case of “independent producers and royalty owners” as defined under §613A(c))
    • This addback to AMTI acts to reduce the tax benefit of the “free tax deduction” for percentage depletion on older and/or very profitable oil and gas wells

As previously touched on, the deduction for percentage depletion under §613 (or §613A in the case of oil and gas wells) has been a target since it was first implemented more than 80 years ago. It also has been included in U.S. Democratic campaign literature as one of the “fossil fuel subsidies” needing to be repealed or pared back. In its latest “Estimates of Federal Tax Expenditures for Fiscal Years 2020-2024,” the Joint Committee on Taxation estimated the tax expenditure related to the “excess of percentage depletion over cost depletion” (for oil and gas) to be $2.9 billion for corporations and “de minimis,” i.e., less than $50 million, for individuals for tax years 2020 through 2024. If the deduction for percentage depletion were to be repealed, this $2.9 billion increase in tax revenue would likely come primarily from smaller corporations due to how the percentage depletion deduction (and its various limitations) is calculated.  

Closing Thoughts

In addition to the deductions for IDCs and percentage depletion, U.S. Democratic Party officials (as well as others) have called for the repeal or removal of the following “fossil fuel subsidies”:

  • Passive activity “exemption” for working interests in oil and gas property (§469(c)(3))
  • Amortization of geological and geophysical expenditures (§167(h))
  • Enhanced oil recovery credit (§43)
  • Credit for producing oil and gas from marginal wells (§45I)
  • Capital gain treatment for certain coal disposals (§631(c))

It remains unclear what (if any) of the proposed changes to the IRC regarding the aforementioned provisions that have historically been beneficial to oil and gas companies (and their owners) will come to pass in the coming years. It’s clear, however, that the incoming presidential administration and Congress won’t be as deferential and hospitable to the energy industry as the outgoing one was.  

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