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IRS 26 CFR § 1.611-2 - Rules applicable to mines, oil and gas wells, and other natural deposits.

February 18, 2019

How Does IRS 26 CFR § 1.611-2 Apply to Mineral Appraisals?


What is applicable in the 26 CFR § 1.611-2 - Rules applicable to mines, oil and gas wells, and other natural deposits when performing a mineral appraisal?

It is prudent to start with the high-level outline of the regulation which is as follows:

  1. Computation of cost depletion of mines, oil and gas wells, and other natural deposits.

  2. Depletion accounts of mineral property.

  3. Determination of mineral contents of deposits.

  4. Determination of fair market value of mineral properties, and improvements, if any.

  5. Determination of the fair market value of mineral property by the present value method.

  6. Revaluation of mineral property not allowed.

  7. Statement to be attached to return when valuation, depletion, or depreciation of mineral property or improvements are claimed.


(1) and (2).  The first two headings are covering depletion.  Depletion is “the using up of natural resources by mining, quarrying, drilling, or felling” according to the Internal Revenue Service (IRS).  The IRS goes on to say that “If you have an economic interest in mineral property or standing timber, you can take a deduction for depletion.”  Finally the IRS says, “A production payment carved out of, or retained on the sale of, mineral property is not an economic interest.”

The take-home message is that depletion is typically applicable to a Working Interest holder that had a capital investment to participate in the depletable minerals.  For a typical royalty holder, depletion is not applicable since a royalty holder is the recipient of a production payment.

(3) The determination of mineral contents of deposits specifies the methods to be used to qualify the minerals.  The method, “…must be made according to the method current in the industry and in the light of the most accurate and reliable information obtainable.”  Minerals are based on type, quantity, and grade.  Type would be oil, gas, or liquids in this case.  Quantity would be in terms of proved reserves for producing minerals.  If there were to be probable or possible minerals as well, those would have to be defined as such and supported by the measurement methodology.  Grade for oil and gas would be based on API gravity or BTU respectively.

The number of recoverable units can be measured from previous years’ measurements.  The previous measurements can be revised downward based on depletion quantities or other new information.  Previous measurements can also be revised upward in the event that new exploration or information has increased the number of recoverable units.


(4)  Determination of Fair Market Value (FMV) of mineral properties, and improvements, if any.  Determining the fair market value of a mineral property as of a specific date to set the basis must be done using only the knowledge that was known or knowable as of the effective date.  This eliminates the possibility of being able to consider information that occurred after the transaction date that would have influenced a hypothetical buyer at the time.  An example might be that a buyer purchased a mineral property then two days later a major discovery was made.  If the information after the transaction was considered, it would dramatically drive the sale price upward.

The second part of paragraph (d) is that the fair market value for dates in the past should lean on comparable sales instead of analytical methods where possible.  The IRS prefers that the basis is based on comparative values or any other method rather than the present value method.  While is does not explicitly state that the present value cannot be used, it states that other comparative or basis of cost methods are preferred.


(5)  Determination of the fair market value of mineral property by the present value method.  When using the present value method, paragraph (e) sets out the essential factors to determine the fair market value.  These are:


    (i) The total quantity of mineral in terms of the principal or customary unit (or units) paid for in the product marketed,


    (ii) The quantity of mineral expected to be recovered during each operating period,


    (iii) The average quality or grade of the mineral reserves,


    (iv) The allocation of the total expected profit to the several processes or operations necessary for the preparation of the mineral for                market,


    (v) The probable operating life of the deposit in years,


    (vi) The development cost,


    (vii) The operating cost,


    (viii) The total expected profit,


    (ix) The rate at which this profit will be obtained, and


    (x) The rate of interest commensurate with the risk for the particular deposit.

The list above is oriented toward Working Interest investments which require all components to be ascertained.  For a passive royalty interest, development costs are not applicable to the royalty holder.  Certain operating costs can be applicable and can sometimes be verified in the lease or the revenue statements if there are any to apply to the model.


The IRS allows past operational history to develop inputs to the model.  Where there is no past operational history, the model should use inputs from “concurrent evidence” that would support a similar operation.  The IRS goes on to specify some areas of inputs and considerations for the model including rate of exhaustion of the mineral deposit, plant capacity limitations, decline in pressure and flow, curtailment of production, and other factors.


The present value of the minerals (oil and/or gas) for a Working Interest is the gross income minus the operating costs reduced to the present value as of the effective date.  The interest rate used in the present value calculation is commensurate with the risk for the operating life.  Improvements and capital additions further reduce the value.


(6)  Revaluation of mineral property is not allowed when the property has an already accepted value and there has been no change of ownership unless there has been a misrepresentation, fraud, or gross error.  The IRS Commissioner must provide written approval to authorize revaluation.


(7) The rules change if the effective date is before December 31, 1967, between January 1, 1968 and December 31, 1968, and after 1968.  Generally for most projects and if the IRS Commissioner continues to require it, a Form O is required.  The Form O should reference the report that Turrett prepared for you.  Check with your tax advisor for their experience and rely on their guidance when making final decisions prior to filing.

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These materials have been prepared solely for educational purposes to contribute to the understanding of oil and gas appraisal. These materials reflect only general concepts in the industry based on Colorado and may not apply to all circumstances.  It is understood that each case is fact ‐ specific, and that the appropriate solution in any case will vary.   These materials may not be relevant or apply to any particular situation.  While every attempt was made to ensure that these materials are accurate, errors or omissions may be contained therein, for which any liability is disclaimed.

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