Energy Insights: Iran & Market Impact

Energy Market Perspective

Ceasefire Eases Oil Markets, but Full Normalization Remains Months Away
The announced ceasefire framework with Iran is good news for energy markets, but it does not mean everything returns to normal overnight. Oil prices moved lower after the announcement, with WTI near $80.75 per barrel and Brent near $83, as markets began removing some of the extra “risk premium” tied to the conflict.

The key issue is the Strait of Hormuz, one of the world’s most important oil shipping routes. Before the conflict, about one-fifth of global oil demand moved through this waterway each day. The shutdown disrupted supply, trapped ships, damaged regional infrastructure, and pushed shipping insurance costs higher. Even with a ceasefire, it will take time to clear the waterway, restart production, lower insurance costs, and rebuild confidence that ships can move safely.

The crisis also highlighted the importance of U.S. oil and gas production, especially in Texas and the Permian Basin. When global supply was disrupted, American producers helped reduce the impact of what could have been a much larger price shock.

Ask the "Tax Guy"

As investors continue to hear the phrase “drill, baby, drill,” it is important to understand what that actually means beyond the headline. For oil and gas investors, the legal right to drill can create more than just access to potential production and cash flow. It may also come with unique tax considerations that are often unfamiliar to everyday investors. This week, we asked our EVP of Tax, Rex Gifford, to explain in plain terms how drilling rights may impact taxes and what investors should know before evaluating an opportunity.

Q.  What are the tax consequences of the legal right to “drill, baby, drill”?

A: To obtain the legal right to drill, legal permission must be secured for a specific location. This is accomplished by negotiating and acquiring a working interest oil and gas mineral lease from the appropriate oil and gas mineral owners. In some cases, surface rights and mineral rights are owned by the same party (often in undivided pro-rata percentages). In other cases, surface owners and mineral interest owners are different parties.

Specific mineral ownership is typically determined by oil and gas landmen who perform a title search of recorded leases at the County Clerk’s office. This process is commonly known as “running title.” Once a mineral lease assignment is properly negotiated and executed (subject to applicable state regulations), an oil and gas well may be drilled within the lease boundaries.

A typical oil and gas mineral lease has a primary term of thirty-six (36) months, with a possible twenty-four (24)-month extension. Most leases provide the original mineral owners (grantors) with a royalty interest, commonly 25% or less of production. In addition, mineral owners are often paid a lease bonus, such as $1,000 per net mineral acre. The acquisition of the working interest is commonly referred to as incurring leasehold costs.

For income tax purposes, the lease bonus paid per mineral acre constitutes the primary leasehold cost. These costs must be capitalized and are not deductible in the current year. These costs are deducted on an annual basis by claiming depletion deductions (either cost depletion or percentage depletion, whichever is greater each year).

Percentage Depletion Deduction (§ 613A(c))
Percentage depletion (generally 15% of gross income from the property) is available only to independent producers and royalty owners, subject to the following limitations:

• Daily Production Limits:
  • Domestic crude oil: limited to the taxpayer’s average daily production that does not exceed the depletable oil quantity (generally 1,000 barrels per day, subject to adjustments).
  • Domestic natural gas: limited to the depletable natural gas quantity (6,000 cubic feet per barrel of depletable oil quantity elected).
• Property-by-Property Net Income Limitation: Percentage depletion cannot exceed 100% of the taxpayer’s taxable income from the property (computed without the depletion deduction). Taxable income from the property is gross income minus allowable deductions for production costs, selling expenses, exploration and development costs, etc. If net income from the property is low or negative, the depletion deduction for that property may be limited or eliminated.
• Overall, 65% Taxable Income Limitation (§ 613A(d)(1)): The total percentage depletion deduction for the year cannot exceed 65% of the taxpayer’s taxable income (computed without regard to the § 613A(c) depletion deduction, the § 199A deduction, certain NOL/capital loss carrybacks, and specific trust distributions). Any excess is carried forward to future years (subject to the same 65% limit) and is allocated pro-rata among properties for basis adjustment purposes.

Cost Depletion is a unit-of-production method (similar to depreciation) that allocates the depletable basis of the property over the resources extracted.

Computation of Cost Depletion:

• Determine the depletable basis (adjusted basis of the property): leasehold acquisition costs + capitalized exploration/development costs (e.g., any capitalized IDCs) + other capitalized items, reduced by prior depletion deductions.
• Estimate total recoverable units (remaining reserves of oil in barrels or natural gas in MCF, based on reliable engineering reports at the beginning of the year).
• Calculate the depletion rate: Depletable basis ÷ Total estimated recoverable units.
• Compute the annual deduction: Depletion rate × Units produced and sold during the year.

Example: Adjusted depletable basis = $100,000; estimated recoverable reserves = 50,000 barrels; 5,000 barrels sold this year. Rate per barrel = $100,000 / 50,000 = $2.00 deduction = $2.00 × 5,000 = $10,000.

Annual depletion deductions are the primary method of recovering the cost of acquiring the legal right to “drill, baby, drill.” As taxable oil and gas production revenue is received, up to 15% of that revenue is generally sheltered from tax through the percentage depletion deduction. Importantly, percentage depletion may continue even after the capitalized leasehold costs have been fully recovered to zero.

Have a tax question you’d like covered in a future issue? Email it to theupside@kingoperating.com.

DISCLOSURE: For educational purposes only. Not tax, legal or accounting advice. Please consult your tax professional before making any investment or tax-related decisions