(c) Oil and gas deposits for which these factors may not be determined with reasonable accuracy from past operating experience may, with the approval of the Commissioner, be valued in a similar manner; but the factors must be deduced from concurrent evidence, such as the general type of the deposit, the characteristics of the district in which it occurs, the habit of the oil and gas deposits in the property itself, the rate at which additional oil and gas has been disclosed by exploitation, the stage of operating life of the property, and any other evidence tending to establish a reasonable estimate of the required factors.

(d) The oil content in the case of oil wells shall be determined in accordance with article 210, and the gas content in the case of gas wells in accordance with articles 212 and 213. The rate of exhaustion of a mineral deposit should be determined by the character of the deposit, by the ability to market the oil and/or gas, by labor conditions, and by the operating program in force or definitely adopted at the basic date for future operations. The operating life of an oil and/or gas property is that number of years necessary for the exhaustion of the property at the rate determined by the actual or estimated rate of decline. The development cost includes all expenditures, such as drilling wells to maintain or increase production; drilling wells to develop additional unproven areas; other improvements necessary to the development of the property, such as roads, warehouses, waterlines, etc. The operating cost includes all current expenditures for producing, preparing, and marketing the oil and/or gas produced, such as pumping oil wells, repairs and renewals of oil or gas wells, cleaning sanded wells, shooting wells, redrilling old wells, labor and supplies for collecting oil, repairs and renewals to separators, pumps, and collecting lines, repairs and renewals to buildings and structures, repairs and renewals to field tools, equipment, fixtures and machinery, superintendence, other field expenditures, extraordinary repairs and renewals, overhead, etc., with due consideration being given to taxes; exclusive of allowable capital additions as defined in article 225 and deductions for depreciation and depletion. The cost of repairs and replacements is not to be confused with the depreciation deduction by which the cost or value of plant and equipment is returnable to the taxpayer free from tax. In general, no estimates of these factors will be approved by the Commissioner which are not supported by the operating experience of the property or which are derived from different and arbitrarily selected periods.

(e) The number of units of mineral recoverable in marketable form multiplied by the difference between the selling price and the operating cost per unit gives the total expected operating profit.

The value of each mineral deposit is then the total expected operating profit from that deposit reduced to a present value as of the basic date at the rate of interest commensurate with the risk for the operating life, and further reduced by the value at the basic date of the depreciable assets and of the capital additions, if any, necessary to realize the profits. The degree of risk is generally lowest in cases where the factors of valuation are fully supported by the operating record of the oil and/or gas property prior to the basic date; relatively higher risks attach to appraisals upon any other basis.

ART. 208. Revaluation of mineral deposits not allowed.-No revaluation of a property whose value as of the basic date has been determined and approved will be made or allowed during the continuance of the ownership under which the value was so determined and approved except in the case of a subsequent discovery as defined in articles 220–223, or of misrepresentation or fraud or gross error as to any facts determinable on the basic date. Revaluation on account of misrepresentation or fraud or such gross error will be made only with the written approval of the Commissioner. The value as of the basic date may, however, be corrected when a virtual change of ownership of part of the property results as the outcome of litigation, and may be redistributed (a) when a revision of the number of units of mineral in the property has been made in accordance with article 209, 210, or 212, and (b) in case of the sale of a part of the property, between the part sold and part retained.

ART. 209. Determination of mineral contents of mine.-Every taxpayer claiming a deduction for depletion for a given year will be required to estimate or determine with respect to each separate property the total units (acres, tons, pounds, ounces, or other measure) of mineral products reasonably known or on good evidence believed to have existed in the ground on the basic date, according to the method current in the industry and in the light of the most accurate and reliable information obtainable. Preference shall be given in the selection of a unit of estimate to the principal unit (or units) paid for in the product marketed. The estimate of the recoverable units of the mineral products in the property for the purposes of valuation and depletion shall include as to both quantity and grade (a) the ores and minerals "in sight," "blocked out," "developed," or "assured," in the usual or conventional meaning of these terms in respect to the type of the deposit, and (b) "probable " or " prospective" ores and minerals (in the corresponding sense); that is, ores and minerals that are believed to exist on the basis of good evidence although not actually known to occur on the basis of existing development; but "probable" or "prospective" ores and minerals may be computed, for purposes of this valuation, (c) as to quantity, only in case

they are extensions of known deposits or are new bodies or masses whose existence is indicated by geological or other evidence to a high degree of probability, and (d) as to grade, of such richness only as accords with the best indications available. If information subsequently obtained clearly shows the estimate to have been materially erroneous, it may be revised with the approval of the Commissioner. ART. 210. Determination of quantity of oil in ground.-In the case of either an owner or lessee it will be required that an estimate, subject to the approval of the Commissioner, shall be made of the probable recoverable oil contained in the territory with respect to which the investment is made as of the time of purchase, as of March 1, 1913, if acquired prior to that date, or within 30 days after the date of discovery, as the case may be. The oil reserves must be estimated for all undeveloped proven land as well as producing land. If information subsequently obtained clearly shows the estimate to have been materially erroneous, it may be revised with the approval of the Commissioner.

ART. 211. Computation of deduction for depletion of mineral deposits. (a) Depletion attaches to the annual production "according to the peculiar conditions of each case," and when the depletion actually sustained, whether legally allowable or not, from the basic date equals the cost or value on the basic date plus subsequent allowable capital additions, no further deduction for depletion will be allowed except in consequence of added value arising through discovery or purchase. See articles 202, 203, 204, and 224.

(b) When the value of the property at the basic date has been determined, depletion sustained for the taxable year shall be computed by dividing the value remaining for depletion by the number of units of mineral to which this value is applicable, and by multiplying the unit value for depletion, so determined, by the number of units sold or produced within the taxable year. The depletion deduction for the taxable year is subject, however, to the limitation contained in article 201 (h). In the selection of a unit for depletion preference shall be given to the principal or customary unit or units paid for in the product sold.

ART. 212. Computation of deduction for depletion of gas wells.-On account of the peculiar conditions surrounding the production of natural gas it will be necessary to compute the depletion allowance for gas properties by methods suitable to the particular cases in question and acceptable to the Commissioner. Usually the depletion of natural gas properties should be computed on the basis of decline in closed or rock pressure, taking into account the effects of water encroachment and any other modifying factors. The gas producer will be expected to compute the depletion as accurately as possible and

submit with his return a description of the method by which the computation was made. The following formula, in which the units of gas are pounds per square inch of closed pressure, is recommended: The quotient of the capital account recoverable through depletion allowances to the end of the taxable year divided by the sum of the pressures at the beginning of the year plus the sum of initial pressures of new wells and less the sum of the pressures at the time of expected abandonment (which quotient is the unit cost) multiplied by the sum of the pressures at the beginning of the taxable year plus the sum of the initial pressures of new wells and less the sum of the pressures at the end of the tax year equals the depletion sustained for the taxable year. The depletion deduction for the taxable year is subject, however, to the limitation contained in article 201 (h).

ART. 213. Gas well pressure records to be kept.-Beginning with 1919 closed pressure readings of representative wells, if not of all wells, must be carefully made and kept. In order to standardize pressure readings the well should remain closed until the pressure does not build up more than 1 per cent of the total pressure in 10 minutes. Ordinarily 24 hours will suffice for this purpose, but some wells will need to remain closed for a longer period. If there is any water in the well it should be blown or pumped off before the well is closed. A closed pressure reading of a gas well which has been producing, or is near gas wells that have been producing, is lower than the actual pressure of the gas in the reservoir by an amount depending on the well's location with reference to other producing wells and the length of time it has been closed in. It is necessary to record the length of time the well has been closed and to show how the pressure built up during this period. Successive readings will indicate the point at which the pressure becomes approximately stationary; that is, the point at which the closed pressure approaches as nearly as possible the maximum pressure which would be shown if all wells in the pool were closed for several months. The length of time required varies with the character of the sand, position of the packer, the location of the well with reference to other wells, the limits of the pool, and other factors. The depth of the well, diameter of tubing, and line pressure when the well was shut off should be noted. Since readings at the exact end of the taxable year will ordinarily not be available, the pressure of that date may be obtained by interpolation or extrapolation. In certain cases readings taken regularly in September or some other month may be applicable to the end of the taxable year. As a general rule September closed pressure readings furnish the best indication of depletion, and it is recommended that such readings be made with regularity and care. Where interpolated or extrapolated readings are used, the data from

which they are obtained should be given. Gauges should be of appropriate capacity and should be frequently tested. A record should be kept of the number of gauges, date each was tested, names of men testing, and other significant details.

ART. 214. Computation of allowance where quantity of oil or gas uncertain. If by reason of the youth of the field, the restricted production, or for any other cause, it is not possible to determine with any degree of certainty the quantity of oil or gas in a property, it will be necessary to make a tentative estimate, which will apply until production figures are available from which an accurate determination may be made.

ART. 215. Computation of depletion allowance for combined holdings of oil and gas wells.-The recoverable oil belonging to the taxpayer shall be estimated for each property separately. The capital account for each property shall include the cost or value, as the case may be, of the oil or gas lease or rights plus all incidental costs of development not charged as expense nor returnable through depreciation. The unit value of the recoverable oil and/or gas for each property is the quotient obtained by dividing the amount returnable through depletion for each property by the estimated number of units of recoverable oil and/or gas on that property. This unit for each separate property multiplied by the number of units of oil and/or gas produced within the year by the taxpayer upon such property will determine the amount which may be deducted for depletion from the gross income of that year for that property, subject, however, to the limitation contained in article 201 (h). The total allowance for depletion of all the oil and/or gas properties of the taxpayer will be the sum of the amounts computed for each property separately. However, in the case of gas properties the depletion sustained for each pool may be computed by using the total amount returnable through depletion of all the tracts of gas land owned by the taxpayer in the pool and the average decline in rock pressures of all the taxpayer's wells in such pool in the formula given in article 212. The total allowance for depletion in the gas properties of the taxpayer will be the sum of the amounts computed for each pool.

ART. 216. Depletion-Adjustments of accounts based on bonus or advanced royalty.-(a) Where a lessor receives a bonus or other sum in addition to royalties, such bonus or other sum shall be regarded as a return of capital to the lessor, but only to the extent of the amount remaining to be recovered through depletion by the lessor at the date of lease. If the bonus exceeds the amount remaining to be recovered, the excess and all the royalties thereafter received will be income and not depletable. If the bonus is less than the amount re