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' Books of special value and gift books, when the ; giver wishes it, are not allowed to circulate. Readers are asked to re- port all cases of books marked or mutilated. Do not deface books by marks and writing. Cornell University Library HJ4169 .U6 "'^"liiniiNilSniilStli?! °'' ^"** 9^* industry unde I Cornell University Library The original of tiiis book is in tine Cornell University Library. There are no known copyright restrictions in the United States on the use of the text. http://www.archive.org/cletails/cu31924030219889 TREASURY DEPARTMENT UNITED STATES INTERNAL REVENUE MANUAL FOR THE OIL AND GAS INDUSTRY UNDER THE REVENUE ACT OF 1918 WASHINGTON GOVERNMENT PRINTING OFFICE r919 r- () U UUtVI:- ' .VY I lliKAKY A 45-1 2.2. S VMAHOM CONTENTS, Pnge. Forewoi'iJ 7 Pakt I. — Amplification of the Law and Regulations. Kinds of taxes imposed .V 9 Limit on surtax aud war-pa'olits and excess-profits tax in case of sale 10 Gross income and net income 12 Basis for deductions 12 Invested capital , 13 "Capital sum" includes "invested capital" 13 Physical property 14 Cost of property 14 Cost of development 14 General expense 15 Repairs 15 Improvements and betterments 15 Compensation for personal services 15 Bonuses to employees 16 Time for deduction of charges 16 Taxes 16 tosses 17 Depreciation 17 Definition 17 Depreciation allowance 18 Depreciable property 18 Depreciation of intangible property IS Capital sum returnable through depreciation allowances 18 Method of computing depreciation allowances 19 Modification of method of computing depreciation 19 Charging off depreciation 19 Closing depreciation account as to any item 20 Depreciation of improvements in the case of oil and gas wells 20 Depletion and depreciation of oil and gas wells in years before 191C- 20 Amortization 21 Depletion of oil and gas wells 22 Capital recoverable through depletion allowance in case of an owner. 22 Capital recoverable through depletion allowances in the case of lessee 23 Illustration 23 Apportionment of deductions between lessor and lessee 24 Determination of cost of deposits 25 Determination of fair market value 25 Ruling regarding valuation 26 No revaluation of property permitted 26 Determination of quantity of oil in ground 27 Methods of estimating recoverable reserves 27 Computation of allowance for depletion of oil wells 28 Computations of allowance for depletion of gas wells 29 Methods of computing gas depletion SO Details of production or the performance record of the well or property 30 Decline in open-flow capacity : 30 Comparison with life 'history of similar wells or properties, particu- larly those now exhausted or nearing exhaustion 30 3 CONTElfTS. Page. Methods of computing gas depletion — Continued. „. Size of i-esei-voir and pressure of gas or the pore space metliod w Other indications of depletion 2j Closed pressure method : 5i Unit costs as applied to natural gas — ?^ ** Corrections and refinements of closed pressure method °^ Method of gauging °^ Apportionment of depletion among various sands 06 Season for testing wells for closed pressure — "4 Formula ^5 Gas well pressure records to be kept 35 Computation of allowance where quantity of oil or gas is uncertain 36 Computation of depletion allowance for combined holdings of oil prop- erties 36 Computation of depletion allowance for combined holdings of gas prop- erties 37 Depletion and depreciation accounts on books 37 Distribution from depletion or depreciation reserve 87 Statement to be attached to a return where depletion of oil or gas is claimed 38 Revaluation of oil or gas properties discovered since March 1, 1013 40 Extract from Regulations 45 40 Charges to capital and to expense in the case of oil and gas wells 41 Depletion for past years not allowed by department 42 ArrENDix TO Pakt I. I. Schedule for ascertainini; cost of property as of any specified date_ 43 II. Schedule fur the valualion of property as of any specified date 47 III. Schedule for proof of discovery 51 IV. Schedule for depletion 52 V. Schedule for depreciation 53 VI. Schedule for the proof of bona fide sale 53 VII. Schedule for computation of iiroflt or loss from sale of capital assets 54 VIII. Schedule for isroving that the principal value has been demon- strated by prospecting or exploration and discovery work done by the taxpayer 55 Pakt II. — Estimate of Depreciation ok KyuiPMENT Useu in the Oil and Gas IXDUSTKY. Preface to Part III 56 Class A, Xo. 1, drilling (■(inipnu'Ut - 57 Class A, No. 2, well equipment 57 Class A, No. 3, dehydrators 57 Class A, No. 4, tanks 58 Class A, No. .5, tools 58 Class A, No. 6, transportation equipment 58 Class A, No. 7, water plants 58 Class A, No. 8, electric equipment 58 Class A, No. 9, machine shop 59 Class A, No. 10, buildings 59 Class B, pipe lines 59 Class 0, tank cars 60 Class C, refineries CO Calculated depreciation for whole refinei-y 61 (a) Complete refinery 61 (6) Skimming jjlant 61 Sales or marketing equipment 62 Natural gas utility companies 63 Natural gas gasoline plants 64 Summary ~ 54 CONTENTS. 5 Part III. — Estimate of Reco\-ekable UxDEBGRorxD Reserves of Oil. Page. Preface 66 .Section A. Methods C8 Soction B, Average future production curves and tables 7.5 Appalacliian district 75 Lima-Indiana and Illinois disti-icts 85 Midcontinent district 91 North Louisiana district IO4 Rocky Mountain district 107 California district 111 Gulf coast of Texas and Louisiana 123 Mexico and other foreign countries 123 ILLUSTRATIONS Page. Fio. 1. Curves illustrating methods C9 2. Curves illustrating methods 70 3. Curves illustrating methods 72 4. Future production curves, Appalachian field 80 5. Future production curves, Lima-Indiana field 87 C. Future production curves, Illinois-Indiana field 89 7. Future production curves, Mid-continent field 00 8. Future production curves, Mid-continent field 99 9. Future production curves, northwest Lousiana Held 100 30. Future production curves. Rocky Mountain Field 109 11. Future production curves, California field 110 12. Future production curves, California field 121 13. Gas decline curves 125 a FOREWORD. This manual is issued to assist the taxpayer of the oil and gas industry in correctly and expeditiously preparing his Federal tax returns. Although the endeavor has been to anticipate all questions that might be asked regarding the law and regulations, and the latter have been amplified when it was deemed necessary to secure the de- sired result, it is recognized that any such manual is merely sugges- tive and can not cover all situations which may exist. The book consists of three parts. Part I deals directly with the law and regulations as they relate to the oil and gas industry. Part II, dealing with the question of depreciation, is included to assist the taxpayer in standardizing his classification of equipment and to offer a suggestion as to relative rates of depreciation for 'different types of physical property. The rates are not to he applied indiscriminately to specific cases, and the Treasury Department is in no way committed to accept them in the returns. Part III consists of descriptions of methods of estimating under- ground oil reserves, especially by means of production ciirves, and a collection of curves and tables covering many of the principal oil ppols and fields in the United States. The curves and tables are intended as a suggestion for the guidance of the taxpayer in the computation of his depletion allowance, which in turn usually has a direct bearing on the amount of his tax. Thej' are not to be applied indiscriminately to specific properties, and the Treasury Department is in no way committed to accept estimates based upon them. Every claim for deduction on account of depletion must be accompanied by a detailed statement of production, etc., upon which such claim is based. Tliese curves and tables are based upon a careful systematic study of thousands of production records; all that could be made avail- able in the limited time at the disposal of the Bureau. Many refine- ments and minor corrections are desirable but must be delayed until more complete records are in hand. With such records it will be possible to make curves to apply to more restricted areas and thus more closely approximate the conditions which apply to individual tracts. Usually it will be to the advantage of the producer to make esti- mates for each property rather than to assume that his particular property is an average. Any or all of the methods discussed may be applied by the producer to his own properties. Obviously, manner of "operation, accidents, and other factors will influence the future production just as they have the past production, but experience has shown that ordinarily these are not likely to cause wide deviation from estimates ^which have been carefully made. Examination of production records of individual properties will show whether the probability of such occurrences will make estimates unsafe. 7 8 MANUAL FOR THE OIL AND GAS INDUSTRY. In ca^^es of appai'ent hardship to the taxpa.yer it will not infre- quently happen that such hardships are the direct result of failure on his part to procure sufficiently detailed records, and, lacking these, great difficulty will be encountered in establishing the facts. Such conditions may have been excusable in the past, but henceforth tlie responsibility rests squarely upon the taxpayer, as his claims must be supported by all necessary data bearing on the case. The investigation resulting in the preparation of this manual was begim before the signing of the armistice, and most of the men who took part in it were called from their usual vocations and undertook the work at a financial sacrifice, and often at great personal incon- venience. The oil operators throughout the country have been most generous in their cooperation in the prosecution of the work, not only as individuals but in th»ir organizations. The hearty support of the Bureau of Mines, Geological Survey, Fuel Administration, and other Federal bureaus has at all times been given. Without the assistance of these agencies the work could not have been finished. The Bureau is therefore greatly indebted to all for their services, and wishes to extend its thanks for their assistance. MANUAL FOR THE OIL AND GAS INDUSTRY UNDER THE REVENUE ACT OF 1918. PAET I. AMPLIFICATION OF THE LAW AND REGULATIONS. KINDS OF TAXES IMPOSED. The Eerenue Act of 1918 levies the following taxes upon the net incomes received by individuals and corporations during the taxable year 1918 : Normal income tax. — Section 210 of the Revenue Act of 1918 levies upon the net income of every individual, a normal tax at the follow- ing rates : For the calendar year 1918, 12 per cent of the amount of. the net income in excess of the credits provided in section 216 : Provided, That in the case of a citizen or resident of the United States the rate upon the first $4,000 of such excess amount shall be 6 per cent. Surtax. — In addition to the normal tax a surtax is imposed at the rates specified in the statute upon the net income of every individual, resident or nonresident. In determining the taxable net income for the purpose of the surtax, the credits provided by section 216 of the statute in the case of the normal tax are not applicable. Computation of surtax. — The following table shows the surtax on net incomes of the specified amounts. In each instance the first figure of net income in the net-income column of the table is to be excluded and the second figure included. The percentage given opposite ap- plies to the excess of income over the first figure in the net-income column, and the sum in the next column is the tax on the entire differ- ence between the first figure and the second figure in the net-income column. The final column gives the total surtax on a net income equal to the second figure in the net-income column. The tax for any amount of net income not shown in the table is computed by adding to the total surtax for the largest amount shown which is less than the income, the surtax upon the excess over that amount at the rate indicated in the table. For example, if the amount of net income is $63,128, the surtax is the sum of $8,690 (the surtax upon $62,000 as shown by the table) plus 30 per cent of $1,128, or $338.40, making a total surtax of $9,028.40. 9 10 MANUAL FOE THE OIL ASTD GAS INDUSTRY. Net income. $5,000 to Sf),000 S6,000to$S,000 98,000 to 810,000 $10,000 to $12,000 812,000 10 si4,noo tl 4,000 to «i6,oon 116,000 CO $1?,000 SIS,000- to 520,000 $20,000 to S22,000 122,000 CO $24,000 $24,000 to $28,000 $2(i,0a0 to $28,000 $28,000 to S30,000 $30,000 to $33,000 S32,000to$3t,308 $34,000 to $36,008 S3a,0O0iO$3S,000 $3 In aU cases iuvolvlDg returns of corporations Part II of Regulations 45 should be consulted. 12 ■ MANUAL FOE THE OIL AND GAS INDUSTRY, Second bracket.— Sixty-five per cent of tlie amount of the net income in excess of 20 per cent of the invested capitah Third bracket.— The sum, if any, by which 80 per cent ot the amount of the net income in excess of the war-profits credits (determined under sec. 311) exceeds the amount of the tax computed under the first and second braclcets. See Part II of the Eegulations. GROSS INCOME AND NET INCOME. Gross income includes all gains and profits and income from any source whatever, subject to the specific exemptions listed in section 213 (b) and section 231 of the Eevenue Act of 1918, actually received for the year for which the return is rendered, whether received in cash or its equivalent. Net income is the amount remaining after all allowable deductions (as listed in sec. 214 (a) and (b) or sec. 234 (a) and (b)) have been made from gross income. BASIS FOR DEDUCTIONS. Certain deductions from gross income are based upon the " Capital Sum"; credits are based upon " Invested Capital." It is necessary that these terms be clearly understood by the taxpayer in order to avuid confusion in making returns. In general, the deductions from gross income allowed corporatiojis arc the same as allowed individuals, except that corporations may de- duct dividends received from other corporations subject to the tax and may not deduct charitable contributions, and that insurance companies are permitted special deductions. INVESTED CAPITAL. The invested capital is defined in section 326 of the Kevenue Act of 1918 as (1) actual cash bona fide paid in for stock or shares; (2) cash value of property, other than cash, bona fide paid in for stock or shares (as limited by the statute) ; and (3) paid in or earned surplus and undivided profits, not including surplus and undivided profits earned during the year. The surplus and undivided profits, if not correctly reflected in the taxpayer's accounts, may be adjusted in accordance with Eegula- tions 4r.. Several of the articles which must ordinarily be considered are sot out below. Regulations 45, article 839. Surplus and undivided profits: Allowance for depletion and depreciation. — Depletion, like depreciation, must be recognized in all cases in which it occurs. Depletion attaches to each unit of mineral or other j^iropcrty removed, and the denial of a de- duction in computing net income under the Act of August 5, 1909, or tlie limitation upon the amount of the deduction allowed under the Act of October 3, 1913, does not relieve the corporation of its obliga- tion to make proper provision for depletion of its i^roperty in com- puting its surplus and undivided profits. Adjustments in respect of depreciation or depletion in prior years will be made or permitted only upon the basis of affirmative evidence that as at the beginning of the taxable year the amount of deprecia- MANUAL FOR THE OIL AND GAS INDUSTRY. 13 tion or depletion written off in prior jears "was insufficient or ex- fessive, as the case may be. Where dednctions for depreciation or depletion haA'e either on the books of the corporation or in its returns of net income been included in the past in expense or other accounts, rather than specifically as depreciation or depletion, or where capital expenditures have been charged to expense in lieu of depreciation or depletion, a statement indicating the extent to which this practice has been carried should accompany the return. Regulations 45, article 842. Surplus and undivided profits property paid in and subsequently written off. — Where tangible or intangible property has been paid in to a corporation for stock or shares or as paid-in surplus and has subsequently been in whole or in part written off the books, the amount so written off may, upon evidence satisfactory to the Commissioner, be restored to the capital or surplus account subject to the following limitations : (1) The amount restored must be reduced by a proper deduction for any depreciation, obsolescence, or depletion ; and (2) The aggregate amount included in computing invested capital on account of such property shall not exceed the amount which might have been included if such property had not been written off. Regulations 45, article 844. Surplus and undivided profits reserve for depreciation or depletion. — If any reserves for depreciation or for de- pletion are included in the surplus account it should be analyzed so as to separate reserves and leave only real surplus. Reserves for de- preciation or depletion can not be included in the computation of in- vested capital, except to the following extent : (1) Excessive depletion or depreciation included therein and which if charged off could be restored under article 871 may be in- cluded in the computation of invested capital ; and (2) Where depreciation or depletion is computed on the value as of March 1, 1913, or as of any subsequent date, the proportion of de- preciation or depletion representing the realization of appreciation of value at March 1, 1913, or such siibsequent date may, if undis- tributed and used or employed in the business, be treated as surplus and included in the computation of invested capital. For the purpose of computing invested capital, depreciation or depletion computed on the value as of March 1, 1913, or as of any subsequent date, shall, if such value exceeded cost, be deemed a pro rata realization of cost and appreciation and be apportioned accord- ingly. Except as above provided, value appreciation (even though evidenced by an appraisal) which has not been actually realized and reported as income for the purpose of the income tax can not be included in the computation of invested caf)ital, and if already re- flected in the surplus account it must be deducted therefrom. The term Capital Sum is here applied to the total amount re- turnable to the taxpayer through depletion, depreciation, and ob- solescence allowances. It is to be clearly distinguished from the term " Invested Capital," which is the basis for the determination of war-profits credits and excess-profits credits of corporations. " Invested capital " is the actual cash or its equivalent, paid in, plus undistributed surplus profits, and no appreciation in the value of any asset may be included except as provided in, article 844 (2). 14 MANUAL ¥y tlie Commissioner, the amount deductible for the taxable year would be $l.j, 000 Amount of depletion, depreciation, and obsolescence calculated on the <(ist of the property is 10,000 The amount of realized appreciation which may be added to invested cimital for the succeeding year is 5,000 Assuming that all the euruiugs are distributed, except the depletion and depreciation reseiTCff, at the beginning of the succeeding tax- able'year, the invested capital would be 55,000 The cost of the property would lie 90,000 The appreciation in value would lie 45,000 Physical property is defined as all equipment having- an inventory or salvage value and subject to, removal from the property such as buildings, bridges, and power plants; derricks, casings,' drillinis of discovery applies to the dis- coverer soUhj. Xo revaluation after March 1, 1913, is allowed where the value of property is enhanced by discovery made by any other than the taxpayer. CAI'lTAL IJFXOVERAltLE THKOUGH DEPLETIOX ALLOWANCE IX CASE OE AN OWNER. In the case of operating owner in fee or lessor the capital recover- able through depletion allowances consists in — MANUAL FOB THE OIL AND GAS INDUSTRY. 23 (a) Cost of the property, or its fair market value as of March 1, 1913, if acquired prior thereto, or its fair market value within 30 days of discovery, as the case may be ; plus (5) Cost of subsequent improvements and development not charged to current operating expenses ; minus (c) Deductions for depletion which have or should have been taken to date ; and minus (d) The portion of the capital sum as to Avhich depreciation instead of depletion has been and is being deducted. The cost or value stated under (a) does not include the value of the land other than as the container of oil and g-as. Depletion may be claimed against that portion of the cost or value which resides in the mineral deposit which is being exploited. To obtain this it is neces- sary to deduct from total cost or value the cost or value of the prop- erty other than as a container of oil and gas. Obviously, the lessor may not include in his capital sum any part of the discovery value or any part of the sums expended by the lessee in the development of the property, as mentioned vmder (b), and the operating owner in fee may include only such costs or values as have not been deducted as current operating expense or otherwise. Where' depletion deductions for former years have or should have been taken, these amounts are to be subtracted from the capital sum returnable through depletion deductions. In no case shall the account returnable through deductions for de- pletion include items against which depreciation is being charged; that is, the cost (or value) of physical property may not be included, since it is returnable through depreciation deductions. CAPITAL EECOVEIiABLE THKOTJGH DEPLETION ALLOWANCES IX THE CASE OF LESSEE. Regulations 45, article 203. — In the case of the lessee the capital remaining in any year recoverable through depletion allowances is the sum of (a) The cost of the leasehold, or its fair market value as of March 1, 1913, Or its fair market value within 30 days after discovery ; plus (h) The cost of subsequent improvements and development not charged to current operating expenses, but minus (c) Deductions for depletion which have or should have been taken to date, and (d) The portion of the capital sum, if any, as to which depre- ciation instead of depletion should be charged. Bonuses constitute a part of the cost of the leasehold. (See cost of property, p. 15.) Any annual or periodical rents or flat royalties (as in the case of gas wells) supplementing the bonuses or other amount paid for the lease at the time of acquisition may be charged to cost of leasehold until the property reaches the operating stage and will form part of the capital returnable through deductions for depletion. ILLUSTRATION. A's invested capital in a leasehold on March 1, 1913, was $200,000. His estimated oil reserves on that date were 2,000,000 barrels. 24 MANUAL rOK THE OIL AND GAS INDUSTRY. Under the Act of 1913, the lessee was not allowed a revaluation lor purposes of computing his depletion deduction from gross in- come. And the depletion taken could not exceed 5 per cent ot the value of the oil at the well. 2 000 000' '^^ ^^ ^®^*^' represents the miit cost of each barrel of oil in the property at that date. lie exti-acts and sells — L!()0,000 barrels in 1913 for $100,000 150,000 barrels in 1914 for 90, 000 125,000 liarrels in 1915 for ^ 60, 000 100,000 barrels in 1916 for 50,000 7r,,o00 barrels in 1917 for 100, 000 He lias sold 650,000 bari'els for $400,000 Depletion Depletion sustained. allowed. 1033 $20,000 $5,000 1914 15,000 4,500 1915 12, .500 3, 000 1910 ]0, 000 10,000 1917 7, .jOO 7, 500 Total .$65,000 .$30,000 For purposes of taxation in 1918 A's invested capital is $200,000— C.'-|,000=$13o,000 and not $200,000-30,000==$170,000. The Eevenue Act of 1918 allows A to revalue his property as of' March 1, 1913. The valuation (" Capital Sum") claimed by A and alloAved by the Commissioner was $1,000,000. The unit cost for purposes of computing depletion deductions from ., , , . $1,000,000 ._ -- , , capital assets is o nno nno ' °^ *0-50 per barrel. . The total depletion of capital sum to January 1, 1918, was, there- fore, G50,OOOX$0.50=$325,000. Capital sum at January 1, 1918, is, therefore, $1,000,000— $;j-J.'i.OOO, or $G7:.,000, and not $l,000,000-$30,000, or $970,000. ArroRTKiNMr.NT or dkductioxs between lessor and lessee. Regulations 45, article 204. — As the value of the property compre- hends the interests of both lessor and lessee, no computation for the purpose of depletion allowances, of the value of these interests sep- aiately as of any date which combined exceeds the value of the prop- el (y in fee simple will be permitted. The same principle applies to lidldors of fractional interests. If the aggregate deduction claimed is deemed excessive, the Commissioner may request the owner or lessee to show that the valuation claimed does not exceed the fair market Aaliie of the property at a specified date determined in the manner explained in Eegulations 45, article 206. The lessor and lessee shall, with the approval of the Commissioner, equitably apportion the allowance in the light of the peculiar conditions in each case and on the basis of their respective interests therein. To the return of every taxpayer claiming an allowance for depletion in respect of (a) a property in which he owns a fractional interest oidy, or (&) a leasehold, or (c) a property subject to a lease, there shall be at- MANUAL FOR THE OIL AND GAS INDUSTRY, 25 tached a statement setting forth the name and address and the pre- cise nature of the holdings of each person interested in the property. In the case of the lessor, the depletion deduction is computed like that of the operating oAvner, except that ordinarily the only amount of capital to be returned is the cost of the oil or gas deposit if ac- quired subsequent to March 1, 1913, or its fair maAet value en Hoc as of March 1, 1913, if acquired prior thereto, or within 30 days of discovery of oil or gas wells if discovered hy the tax-payer. The value of the land for purposes other than as a container of oil or gas must always be deducted from the cost or value above to obtain the cost or value of the oil or gas deposits. Such cost or value divided by the estimated units of oil or gas in the ground on the date of acquisition or valuation will give the unit cost or value to be applied against the number of units removed from the lessor's property by the lessee, irrespective of the amount of oil received by the lessor as royaltj'. However, in cases where the property was leased before March 1, 1913, at a -fixed price per unit, instead of a royalty payable in kind the lessor would be re- stricted by the valuation indicated by such fixed price, as fluctuations in the market value of oil subsequent to the lease would affect the valuation of the lessee only. DETERMINATION OF COST OF DEPOSITS. Regulations 45, article 205. — In any case in which a depletion or depreciation deduction is computed on the basis of the cost or price at which any mine, mineral deposit, mineral rights, or leasehold was acquired, the owner or lessee will be required upon request of the Com- missioner to show that the cost or price at which the property was bought was fixed for the purpose of a bona fide purchase and sale, by which the property passed to an oAvner, in fact as AAell as in forni, different from the vendor. No fictitious or inflated cost or price will be permitted to form the basis of any calculation of a depletion or depreciation deduction, and in determining whether or not the price or cost at which any pur^ chase or sale Avas made represented the actual market value of the property sold, due weight will be given to the relationship or con- iiection existing betAveen the person selling the property and the buyer thereof. In general,' the taxpayer will be required to submit the information called for in Schedule 1, page 43. DETERMINATION OF FAIR MARKET VALUE. INTRODUCTORY STATHSIENT. A determination of the fair market A'alue of an oil or gas property (or the taxpayer's interest therein) is required: (a) In connection with the computation of depletion alloAvances: (1) As of March 1, 1913, in the case of properties acquired prior to that date ; and (2) At the date of discovery or tuithhi SO days thereafter in the case of oil and gas wells, discovered by the taxpayer on or after March 1, 1913, and not acquired as the result of purchase of a proven tract or lease where the fair market value of the property is disproportionate to the cost. 26 MANUAL JOE THB OIL AND GAS INDUSTRY. (i) In connection with computing the amount which may be in- chided in paid-in surplus, as of date of conveyance, where the tan- gible property has been conveyed to a corporation by giit or at a value accurately established or definitely known as at date of con- veyance clearly and substantially in excess of the cash or of the par value of the stock or shares paid therefor. (c) In connection with the computation of profit and loss from sale of capital assets in the case of properties acquired prior to March 1, 1913. Eegulations 45, article 206. — Where the fair market value of the property at a specified date in lieu of the cost thereof is the basis for depletion and depreciation deductions, such value must be deter- mined, subject to approval or revision by the Commissioner, by the owner of the property in the light of the conditions and circum- stances known at that date, i-egatrdless of later discoveries or de- ■velopments in the property or in methods of mining or extraction. The value sought should be that established assuming a transfer between a willing seller and a willing buyer as of that particular date. . Xo rule or method of determining the fair market value of min- eral property is prescribed, but the Commissioner will lend due weight and consideration to any or all factors and evidence having a bearing on the market value, such as {a) cost, (&) actual sales and transfers of similar properties, (c) market value of stock or shares, {d) royalties and rentals, (e) value fixed by the owner for the pur- poses of the capital-stock tax, {f) valuation for local or State taxa- tion, {g) partnership accountings, (A) records of litigation in which the value of the property was in question, {i) the amount at which the property may have been inventoried in probate court, (;') dis- interested appraisals hy approved methods, and {h) other factors. In order to meet the requirements of the case to the satisfaction of the Commissioner the taxpayer will be required to submit the information called for in Schedule II. See also Proof of Discovery, page 40. RCLIXd REGARDING VALUATION. Valuation of fee under lease. — The valuation of a fee ownership in oil or gas land under lease acquired prior to March 1, 1913, will have to do with the equity in its oil and gas contents remaining to the owner of the fee title after deducting the value of the lessee's riglits. But subsequent investments or discoveries by the lessee will not affect the lessor's valuation. NO nE\ALUATION OF PROPERTY PERMITTED. Regulations 45, article 207.— The cost of the property or its fair market value at a specified date, as the case may be, plus subsequent charges to capital sum not deductible as current expenses, will be the basis for determining the depletion and depreciation deductions for each year during the continuance of the ownership under which the fair market value or cost was fixed, and during such ownersliip there can be no revaluation for the purpose of this deduction. This rule will not forbid the redistribution of the capital sum over the estimated number of imits remaining in the property in accordance with either of the next two articles. MANUAL FOR THE OIL AND GAS INDUSTRY. 27 DETERMINATION OF QUAXTITr OF OIL IN GROUND. Regulations 45, article 209. — 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, or 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 unde- veloped proven land as well as producing land. If information subsequently obtained clearly- shows the estimate to have been mate- rially erroneous, it may be revised with the approval of the Com- missioner. The estimate of probable recoverable oil in the ground is funda- mentally necessary if a reasonable deduction for depletion is to be calculated, and, while it may be impossible to detennine exactly the future production of a well or tract, it has been found possible to predict future productions with a comparatively narrow limit of error. The result of analj^sis of a great volume of production records has led to the development of the methods suggested in Part III of the Manual. METHODS or ESTIMATING RECOVERABLE RESERVES. The Treasury Department does not prescribe any particular method of estimating recoverable reserves, but the methods described in Part IV of the Manual are applicable to a wide variety of conditions and are ijiserted as a suggestion. The underlying principle of the methods outlined is that the iest indication of the future 'production of any well is to he found in the history of similar ivells in the same or similar districts, and that, other things being equal, a well's production is more likely to ap- proximate the production of r. similar well in the tract or district than to deviate widely from the average. The method may be summarized as follows : 1. Plotting the record of production of individual wells, or, lack- ing such detailed information, the average production per well for each tract. 2. Deriving from these graphical records an average or composite production clecline curve for the district. 3. Estimating from the last year's average production per well the probable future production, based on the average production decline curve, or a future production curve derived from the pro- duction decline curye. 4. Ascertaining probable total future production of producing wells by multipTying average future production per well by the number of wells producing at the end of the year. 5. Estimating the probable future production of undeveloped proven land on the basis of near-by production, making due allow- ance for the decline in pressure due to the extraction ^t oil from the pool. It is to be emphasized that the value of estimates will depend ahnost entirely upon the skill with which the method is carried out and the character of the production records upon which they are 28 MANUAL rOR THE OIL AND GAS INDUSTRY. based. Where accurate detailed records are not kept, it may be difficult to determine a " reasonable allowance for depletion. The taxpayer may estimate his recoverable reserves by any method that can be shoAYn to be well founded, but in all cases the data upon which such estimate was based must be submitted, with a descrip- tion of the method employed, and a resume of the calculations. COMPUTATION OF ALLOWANCE FOR DEPLETION OF OIL WELLS. Regulations 45, article 210. — When the cost or value as of March 1, 1913, or within 30 days after the date of discovery of the property, shall have been determined, and the number of mineral units in the property as of the date of acquisition or valuation shall have been estimated, the division of the former amoimt by the latter figure will give the unit value for the purposes of depletion, and the depletion allowance for the taxable year may be computed by multiplying such unit value by the number of units of mineral extracted during the year. If, however, proper additions are made to the capital account represented by the origmal cost or value of the property, or circum- stances make advisable a revised estimate of the number of mineral units in the ground, a new unit value for purposes of depletion ma)' be found by dividing the capital account at the end of the year, less deductions for depletion to the beginning of the taxable year which have or should have been taken, by the number of units in the ground at the beginning of the taxable year. This number, unless a revision of the original estimate has been made, will equal the num- ber of units in the ground at the date of original acquisition or valua- tion less the number extracted prior to the taxable year. If, how- ever, a recalculation is made, the number of units at the beginning of the year will be the sum of the gross production of the year and the estimated mineral reserves in the property at the end of the year. Each barrel of oil or unit of gas extracted and marketed must, before a profit can be realized, pay not only its proportionate share of tlie operating expense and deductions for depreciation and obso- lescence of physical property, but also must pay its proportionate sluire of capital sum returnable through depletion allowances. (See above. ) J his proportionate share of capital sum returnable through depletion allowances, which each unit of oil or gas must pay, is unit cont. l^nit cost is obtained by dividing the capital sum returnable through depiction by the " estimated recoverable reserve " at the be- ginning of the taxable year. Tlie depletion deduction is computed by multiplying the imit cost by the number of units produced cluring the taxable year. It is 1() be noted that the estimated recoverable reserves and the number of units produced are used in estimating the depletion deduc- tion for both lessor and lessee. Since, however, they are applied to different capital amounts returnable through depletion deductions, tlie unit costs for lessee and lessor are not identical, and the deduc- tions bear the same ratio as the capital sum of lessor and lessee. Usually the lessee's investment is greater than the lessor's and his deductions are correspondingly greater. MANUAL FOE THE OIL AND GAS INDUSTRY. 29 Stated in another way, if a certain proportionate part of the lessee's capital returnable through depletion deductions is deducted in a given year the same proportion of the lessor's capital sum re- turnable through depletion will be deducted. (See apportionment of deductions between lessor and lessee.) Illustration : A, a lessee, has an oil lease in which his original investment (exclusive of value of physical property) was $20,000 Development cost (exclusive of cost of physical property) not otherwise deducted ; . 80, 000 Capital returnable through depletion allowance $100, 000 Estimated recoverable reserves at end of taxable year barrels 400, 000 Produced during taxable year : do 100, 000 Estimated oil at beginning of year , do 500,000 Therefore unit cost is rnn noo ' °'' ^^^' '^'^I'^'^l $0.20 A's depletion allowance for the taxable year is, therefore, $0.20X100,000, or ^ $20,000 B. the owner in fee of the property, had invested $40, OQO Of which the value of the land exclusive of oil rights represents 25, 000 The investment in the oil deposit is $15, 000 B's unit cost is, therefore, §f^' °^ P"?"^ '^^rrel _ $0. 03 And his depletion allowance for the same year $0.03 }< 100,000, or $3, 000 The above example presupposes that B leased his land without bonus. Any amount received by a lessor as bonus for an oil and gas lease on the property would reduce his capital sum by that amount. Illustration: The lessor's (B's) investment in the deposit iS— ,$15, OOO He receives as bonus 5, 000 His net investment in the deposit is, therefore $10, 000 He sells a one-half interest in his royalty for $6, 000 As this half cost him 5, 000 His profit is $1, 000 And is subject to tax as income. His capital sum remaining is . $.5,000 If he had sold a one-half interest in his royalty for . 4, 000 He would have sustained a loss of . $1, 000 and sliould deduct this amount from gross income as a loss in computing his tax. COMPUTATIONS OF ALLOWANCE FOR DEPLETION OF GAS WELLS. Begulations 45, article 211. — The deductions allow'ed in computing income from natural-gas properties are in general similar to those allowed oil operators, but the method of computing the deductions and the various assets differ in certain particulars, the most notable 30 MANUAL FOR THE OIL AKD GAS INDUSTRY. of which are invohed in the problems of estimating the probable reserves and computing the depletion. On account of the peculiar conditions surrounding the production of natural gas it is necessary to compute the depletion allowance for gas properties by methods suitable to the particular cases. Usually the depletion 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. In many fields more or less addi- tional evidence on depletion is to be had from such considerations as (a) details of production and performance recordsof well or prop- erty, (&) decline in open flow capacity, (c) comparison with the life histories of similar wells or properties, particularly those now ex- hausted, and (d) size of reservoir and pressure of gas. METHODS OF COMPUTING GAS DEPLETION. Details of production or the performance record of the well or prop- erty. — As a general rule the demand on a natural gas property is a variable factor. In certain fields, however, the demand from some wells has from the beginning, or for considerable periods, been greater than the supply, so that the amount of gas marketed per well may, as in the case of oil. show a regular decline, wliich will be indica- tive of the total amount that the well may be expected to produce, and also the rate of production. Even where the demand does not greatly exceed the supply, the amount and rate of past production may in certain cases throw light on the future of the well or property. Decline in open-flow- capacity, — AA'here data are available the de- cline in open-How capacity indicates in a general way the rate of , exhaustion of the gas field. The relationship is not at all close and varies from field to field and from well to well. Also for most gas wells accurate data on decline in open-How capacity are not available. Nevertheless it is probal)le tliat for certain properties this method will have value, for with rare exceptions the production of gas from a well leads to a decline in its capacity, and the fraction produced is roughly proportional to the decline. Comparison with life history of similar wells or properties, particularly those now exhausted or nearing exhaustion. — Where no other data are availal)le the rate of depletion of a gas well or property may be ap- proximated by comparison with a neighboring well or property that has reached a later stage in life. Particularly is this applicabje in a district where many gas wells have become exhausted. For example, in a region where wells produce from 8 to 12 years, or an average of 10 years, a 10 per cent deduction will be a rough approximation of the rate of dc]iletion. Size of reservoir and pressure of gas, or the pore-space method. — For some ])ropcrties the pore-space method may be best for estimating underground supplies of natural gas and for a good many it will furnish additional evidence of value. The method would be ideal if the average percentage of pore space, the extent and thickness of the sand, and the ijressnre of the gas could be accurately ascertained. In computing the reserves of an individual property by this method the migratory character of gas must be considered and the produc- tion and behavior of adjacent properties taken into account. The factors that make the method difficult to apply are difficulty of MANUAL FOR TH]i OIL, AND GAS INDUSTRY. 31 • accurately ascertaining the thicltness of pa)', limits of pool, per- centage of pore space, the effect of encroaching water and oil, and the quantity of gas remaining when commercial production is no longer possible. Take, for example, a pool where there is no encroachment by water. Suppose that the pore space is 25 per cent, the thickness of the pay 20 feet, and the extent of the pool 10 square miles, or roughly 280,000,000 square feet. The volume of the reservoir would be 1,400,- 000,000 cubic feet, and the amount of gas in the sand could be readily computed by taking into account the closed pressure of the wells. Other indications of depletion. — Additional evidence of decreasing suppl}' of natural gas in the ground is commonly observable in the behavior of the wells and the provision that must be made for trans- porting the gas to market. Observations on minute pressures show more or less progressive change as the wells become older and an increasing amount of gas is drawn from the ground. Line pressures and pressures at compressing stations are also likely to show a progressive change in the same direction. The appearance of water or oil in a gas well or in neighboring gas wells may be a very sig- nificant symptom of the approaching termination of the life of the well. The clogging of gas wells by paraffin, salt, or other deposits may demand modification of depletion estimates. CLOSED-PRESSURE METHOD. Because of its general applicability, the closed-pressure method is by far the best method of estimating the depletion of gas prop- erties. Unfortunately, accurate closed-pressure data have not been kept for all properties or perhaps even for the majority of properties, but the rock pressure in most pools' is known or is ascertainable with a fair degree of accuracy, and the information drawn from the pressure decline is, with the exception of a few fields, not subject to profound modification, because of factors whose value can not be appraised. The basis of this method is Boyle's law. According to this law of physics, if gas is pumped into a vessel until the pressure is 200 pounds and then is drawn off until the pressure is 100 pounds, the size of the vessel remaining fixed, and ignoring for the moment atmospheric pressure, it may be concluded that one-half of the gas has been drawn out of the vessel. If an underground gas reservoir of fixed dimensions is tapped by wells and the pressure is found to be a thousand pounds, and then if the gas is drawn off through the wells until the gas pressure in the pool is lowered to 100 pounds, we may infer that about nine-tenths of the supply of gas has been exhausted. "Unit cost" as applied to natural gas. — Although, as a rule, the number of cubic feet of gas under a tract can not be satisfactorily estimated and the quantity that will be marketed is even less definite, the '' unit cost method " can be used by regarding pounds of closed pressure as units, for the actual c^uantity of gas underground com- monly varies with the decline in pressiu'e and the relative quantity at the beginning and end of the tax year and at the time of abandon- ment, is, in the lack of better information, usable for tax purposes. 32 MANUAL FOR THK OIL AND GAS INDUSTRY. Corrections and refinements of closed-pressure method.— Several cor- rections and more or less important refinements are made in ap- pjying this method to the computation of depletion, and it should be borne in mind that it does not aii'ord data on the amount of gas originally in the pool or at any later specified time, but only the fraction of the gas that has been removed from its natural res- ervoir and the fraction remaining in that reservoir. Perhaps the most important of these corrections arises out of the fact that the size of the reservoir does not remain fixed but becomes smaller as the gas is draAvn and water or oil advances into a part of the space for- merly occupied by the gas. The pressure is thur prevented from declining at a rate proportionate to the amount of ^as drawn from the pool. The correction on account of water or oil encroachment is difficult to make, because of the lack of data to determine the ex- tent of the encroachment. However, in a good many pools, after a study of the distribution of wells that have been " drowned out " and the history of Avater troubles in similar near-by pools, it is pos- sible to make allowance for water or oil encroachment which will more or less closely approximate the facts. Another refinement applicable to the computation of depletion of natural gas by the closed-pressure method is based upon the fact that even where there is no encroachment of water or oil the deple- tion is not precisely represented by the gauge readings, though the errors are generally so small that they may be ignored. For ex- ample, where the pressure declines from 1,000 to 500 pounds, the gas is not exactly half gone, for the season the pressures referred to are gauge readings and to each should be added the pressure of the atmosphere — for most fields about 14.4 pounds to the square inch. The fraction remaining in the ground then becomes ^^fyf^-- Account should also be taken of the pressure at which wells are abandoned in tlie field or district. If wells can not be operated with profit after the pressure has declined to 25 pounds gauge reading (39.4 pounds absolute), then the percentage of recoverable gas remaining when the pressure has declined from 1,000 to 500 pounds gauge reading is not one-half or even the fraction ^V/i^ '^"t Iff- The difference in the fraction wliere pressures of several hundred pounds are involved is not great and scarcely worth considering in view of the other errors which are certain "to affect the result. However, after the pressure has de- clined to a low figure, the matter of correcting the fraction becomes of considerable importance. Thus, if the pressure of abandonment is 4 pounds gauge reading and during the year the average closed pressure of a pool has declined from 10 pounds to 5 pounds gauge reading, five-sixths instead of one-lialf of the recoverable gas has licoii withdiawn. Still another refinement that has, as a rule, more theoretical than practical value may be Avorthy of consideration in certain instances. Tliis arises out of the fact the gases do not expand precisely as the ]n'essure decreases, and tliat even if the size of tlie natural reservoir remains fixed the pressure does iwt decline In exact proportion to the amount of gas removed. The difference amounts to only a few per cent and is greatest for high pressures. In the decline from 1,000 to 500 pounds per square inch the gas expands several per cent more than would be calculated by a strict application of Bovle's -MANUAL rOK THE OIL AND GAS INDUSTRY. 33 law, and in a decline from 1,500 pounds to 1,000 pounds the departure is. still greater. The correction varies frona field to field because of the different constitution of the gases, though since most natural gases consist largely of methane the variations on account of differ- ences in gases are not great. A fourth detail of refinement arises out of the fact that on the average more gas is marketed for 50 pounds of decline in pressure after the pressure has reached 100 pounds or less than an equal decline while the pressure is high, as, for example, 1,000 pounds per square inch. Also the expense of marketing ^as after the pressure has become low is greater than Avhen it was high, largely because of the necessity of installing compressors to push the gas through the pipe lines to the consumers. These two considerations have a tend- ency to balance each other and, with certain exceptions, will not be of sufficient importance to warrant an attempt to apply the corrections. METHOD OF GAUGING. In using the closed-pressure method of estimating depletion, the method of gauging is of vital importance and in many fields is not carried out with sufficient care. Care should be taken to make sure that the gauge is accurate, testing it before and after attaching it to the well. If it must be transported far or is subject to much jolting in transportation, a gauge tester should be taken along and used at the well. Care should also be taken to empty the well of oil and water by pumping, blowing, or siphoning before attaching the gauge, for any liquid in the hole will lower the closed pressure reading. The well should be closed long enough to allow the pressure to build up to its maximum. The length of time necessary for this purpose varies a great deal from field to field and well to well. The well should remain closed until the pressure will not build up more than 1 per cent in 10 minutes. Ordinarilj', 24 hours will be sufficient for this purpose, but for some wells several days or even a longer period will be required, owing to the slowness of equalization of pres- sure in the sand. APPORTIONMENT OF DEPLETION AMONG VARIOUS SANDS. Where more than one sand under a property is j'ielding gas, the problem arises as to how to weight or evalulate the decline in pres- sure in the different sands. Suppose there is a very good gas sand in which the pressure declines from 600 to 300 pounds during the year, and a very poor sand in which the pressure declines from 800 to 750. The depletion sustained is not indicated by the average decline in pressure but is more nearly proportionate to the decline in the good sand. If accurate figures on capacities of wells are obtainable, it will be possible to make a fairly accurate weighting of the pressure declines, or if facts indirectly indicating capacity of individual wells are obtainable some light may be thrown on the question. But, as a general rule, it is necessary to average the decline of wells drawing from different sands as though they were drawing from the same sand. 111069°— 19 3 S4 MANUAL FOR THE OIL AND GAS INDUSTRY, SEASON FOR TESTING WELLS FOR CLOSED PRESSURE. For many fields summer or early fall readings furnish tlie best .in- dication of decline in closed pressure. It is therefore recommended that such readings be taken regularly and consistently. Summer or fall readings are of especial value because these seasons for most fields are at the end of a period during which the wells have not been subject to heavy draft, and hence are in best condition to accu- rately reflect the pressure of the gas in the underground pool or reservoir. If pressures of all wells or representative wells are ob- served regularly and carefully in summer or early fall, these readings may in many cases be applied direct to the end of the taxable year, though in some cases it may be possible and desirable to estimate the pressures at the end of the taxable year from pressures observed at other times. Obviouslj', it will not be possible to test the pressures of all wells at the exact end of the taxable year. Simple examples. — If in one part of a tract a gas well is brought in at a pressure of 1,000 pounds and during the remainder of the tax- able year the pressure declines to 700 pounds, the rough inference may be drawn that tliree-tenths of the gas has been taken from the tract and, subject to corrections in certain cases, three-tenths of the capital returnable through depletion may be charged off. Suppose that sometime in the next taxable year a gas well is com- pleted on another part of the tract and that its initial pressure is 800 pounds. If by the end of the year the ]nes^nre of this well has de- clined to 700 pounds while the pressure of the first mcU has dropped to 500 pounds, the fraction of the capital account returnable through depletion the second year is proportional to the average decline in pressure, assuming that there are no water troubles or other note- worthy complications. The average of 700 and 800 is 750 and the average of 500 and 700 is GOO. The difference or average decline in pounds or units of gas is 150, and this represents a decline of 20 per cent from 750. It will be noted that the exact date of completion of the new well does not enter the computation and it is treated as though it were finished at the beginning of the year. The rate of decline within the j'ear is of little consequence, the main considera- tion being the amount of decline for the whole year. If the year's decline occurred within a month, or even a week, it is treated the same as though it were spread over the entire year. Abandoned wells may be regarded as fully depleted and their pressure counted as zero in computing depletion. Consider the wells just described and assume that in the third year a third well is brought in and one of the old wells is abandoned. Suppose the pres- sure at the first well declined from 500 pounds to about zero and the well is abandoned, the second well to 300 pounds and the third to 600. The pressure of the two old wells at the beginning of the year and of the nev,- one at its completion averaged COO pounds, and the average of the three at the end of the year was oOO. The depletion indicated is 50 per cent of the remaining capital account. It is suggested that the capital siuu at the beginning of each year be treated as 100 per cent for the average pressure at the begin- ning of the year, and the average decline during the year will then furnish n readily usable basis for computing the depletion allowance. The amount of gas in the ground is, as a rule, to be ret^arded as MANUAL FOB THE OIL, AND GAS INDUSTRY, 35 limited to the proven territory so that as new wells are drilled and the territory is enlarged, or new gas-bearing sands are discovered, the denominator of the fraction, indicating depletion, varies from year to year. FORMULA. The following discussion is offered for the use of those who prefer to use a formula in computing the depletion allowance. Perhaps the simplest formula may be written : — X3=depletion allowance. In this formula x stands for the capital sum to the end of the year; y is the total future pressure decline or the difference between the sum of the pressures at the beginning of the tax year and the sum of the pressures at the time of expected abandonment; s is the pressure decline during the year as obtained by adding to the sum of the pressures at the beginning of the year the sum of the pressures of any new wells completed during the year and subtracting the sum of the pressures at the end of the year. The formula may also be writ- ten as follows: Sum of pressures at beginning of tax Capital sum to end of tax year ^^ ^^^^ + ^^]^ °^ Denletion —^ :~-Pj — . , -^ ■ — X pressures of new = -^^^^icuiuu Sum of the pressures at begm- ^ells sum of allowance. ning of year -sum of pressures pressures at end at time or expected abandon- ^r . ment. ' -^ ' ' GAS WELL PRESSURE RECORDS TO BE KEPT. Regulations 45, article 212. — 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. Where the pressure builds up very slowly the 1 per cent in 10 minutes will be found too liberal. If there is any water in the well it should be blown, siphoned, 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 average 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. Succes- sive readings will indicate the point at which the pressure becomes approximately stationary; that is, the point at Avhich the closed pressure approaches as nearly as possible the maximum pressure 36 MANUAL FOR THE OIL AND GAS INDUSTRY. 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 refer- ence to other Avells, the limits of the pool, and other factors. The depth of the well, diameter of tubing, and line pressure when the Avell 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 inter- polation 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 read- ings furnish the best indication of depletion, and it is recommended that such readings be made with regularity and care. Where inter- polated 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. Kecord should be kept of the number of gauges, date each was tested, names of men testing, and other significant details. COMPUTATION OF DEPLETION ALLOWANCE WHERE QUANTITY OF OIL OR GAS IS UNCERTAIN. Eegulations 45, article 213. — Computation of depletion allowance where quantity of oil or gas uncertain. — If by reason of the youth of the field, restricted production or for any other cause, it is not possible to de- termine 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 luitil production figures are available from which an accurate estimate may be made. COMPUTATION OF DEPLETION ALLOWANCE FOR COMBINED HOLDINGS OF OIL PROPERTIES. Regulations 45, article 214 (1). — The recoverable oil belonging to the taxpayer shall be estimated separately on the smallest unit on M'hich data are available, such as individual wells or tracts, and tlicsc, added together into a grand total, to be applied to the total capital assets rctui-nable through depletion. The capital sum shall include the cost or value, as the case may be, of all oil rights, freeholds, or leases, plus all incidental costs of development not charged as expense. The unit value of the total recoverable oil is the quotient obtained by dividing the total capital sum recoverable through depletion by the total estimated recoverable oil at the beginning of the taxable year. This unit multiplied by the total number of units of oil produced by the taxpayer during the taxable year from all of the oil properties will determine the amount which may be allowably deducted from the gross income of that year. In tlie case of sale of particular tracts, full account must be taken of the depletion of such tracts in computing profit or loss thereon. MANUAL FOR THE OIL AND GAS INDUSTRY. 37 COMPUTATION OF DEPLETION ALLOWANCE FOR COMBINED HOLDINGS OF GAS PROPERTIES. - Regulations 45, article 214 (2). — In tlie case of gas properties of a taxpayer the depletion allowance for each pool may be computed by using the combined capital sum returnable through depletion of all tracts of gas land owned by the taxpayer in the pool and the average decline in rock pressure of all the taxpa3^er's wells in each pool in the formula given in article 211. The total allow'ance for depletion of the gas properties of the taxpaj'er will be the sum of the amounts computed for each pool. The depletion of gas supplies belonging to a taxpayer may be more accurately computed by making estimates for each tract, though it is quite possible that the expense of making separate estimates for individual tracts may be greater than the benefits arising from such a procedure. DEPLETION AND DEPRECIATION ACCOUNTS ON BOOKS. Eegulations 45, article 216. — Every taxpayer claiming and making a deduction for depletion and depreciation of mineral property shall keep accurate ledger accounts in which shall be charged the fair market value as of March 1, 191-3, or within 30 days after the date of discovery, or the cost, as the case may be (a) of the property, and (6) of the plant and equipment, together with (c) such amounts expended for development of the property or additions to plant and equipment since that date as have not been deducted as expense in his returns. These accounts shall be credited with the amount of the deprecia- tion and depletion deductions claimed and allowed each year, or the amounts of the depreciation and depletion shall be credited to de- pletion and depreciation reserve accounts, to the end that when the sum of the credits for depletion and depreciation equals the value or cost of the property plus the amount added thereto for development or additional plant and equipment, less salvage value of the physical property, no further deduction for depletion and depreciation with respect to the property will be allowed. Because of the fact that depreciation and depletion deductions are applied against different capital sums, which are usually returnable at different rates, it is essential that these accounts be kept separately ; that is, the cost or value of physical property subject to depreciation with deductions for depreciation enter into one account, while the cost or value of the property (exclusive of physical property), together with additions for such development costs as have not been charged to current operating expenses or deducted as depletion, enter into a separate account. If dividends are paid out of a depletion or depreciation reserve, the stockholders must be expressly notified that the dividend is a return of capital and not an ordinary dividend out of profits. DISTRIBUTION FROM DEPLETION OR DEPRECIATION RESERVE. A reserve set up out of gross income by a corporation and main- tained for the purpose of making good any loss of capital assets on account of depletion or depreciation is not a part of its surplus out of which ordinary dividends may be paid. 38 MANUAL FOR THE OIL AND GAS INDUSTRY. A distribution made from such a reserve will be considered a liqui- dating dividend and will constitute taxable income to a stockholder only to the extent that the amount so received is in excess of the cost. or fair market value as of March 1. 1913, of his shares of stock. No distribution, however, will be deemed to have been made from such a reserve, except to the extent that the amount paid exceeds the sur- plus and undivided profits of the corporation. In general, any distribution made by a corporation other than out of earnings or profits accumulated since Februarv 28, 1913, is to be regarded as a return to the stockholder of part of the capital repre- sented in his shares of stock, and upon a subsequent sale of such stock his profit will be the excess of the selling price over the cost of the stock or its fair market value as of March 1, 1913, after applying on such cost or value the amount of any such capital distribution. STATEMENT TO BE ATTACHED TO RETURN WHERE DEPLETION OF OIL OR GAS IS CLAIMED. Regulatitfns 45, article 218. — To each return made by a person own- ing or operating oil or gas properties there should be attached a statement showing for each property information called for in Schedules I, II, and IV. (a) (1) The fair market value of the property (exclusive of ma- chinery, equipment, etc., and the value of the surface rights) as of March 1, 1913, if acquired prior to that date; or (2) the fair market value of the property within 30 days after the date of discovery; or (3) the actual cost of the property, if acquired subsequent to Feb^ ruary 28, 1913, and not covered by the foregoing clause; (5) How the fair market value was ascertained, if the property came under (a) (1) or (a) (2) above (see sections relating to fair market value, p. 25) : (c) The estimated quantity of oil or gas in the property at the time that the value or cost was determined ; (d) The name and address of the person making the estimate and the manner in which this estimate was made, including a summary of the calculations; (e) The amount of capital applicable to each unit (this being found by dividing the value or cost, as the ca:ie may be, by the esti- mated number of units of oil or gas (pounds per square inch in the case of gas) in the propertv at the beginning of the taxable year) ; (/) The quantity of oil or gas produced during the year for which the return is made (in the case of new properties it is desirable that this information be furnished by months) ; iff) The number of acres of producing and proven oil or gas land ; (A) The number of wells 2ii'oducing at the beginning and end of the taxable j^ear ; (/) The date of completion of wells finished during the taxable year; (j) The date of abandonment of all wells abandoned during the taxable year; (k) A legal description of the property, with a property map showing the location of the proj^erty and of the productinof and abandoned wells, diy holes, and proven oil and gas land; MANUAL. FOE THE OIL AND GAS INDUSTRY. 39 (l) The average gravity of the oil produced on the tract ; (m) The number of pay sands and average thickness of each pay sand or zone on the property ; (n) The average depth to the top of each of the different pay sands; (o) Any data regarding change in operating conditions, such as flooding, use of compressed air, vacuum, shooting, etc., which luave a direct effect on the production of the property ; (p) The monthly or annual production of individual wells and the initial daily production of new wells (this is highly desirable in- formation and should be furnished wherever possible) ; (q) (For the first year in which the above information is filed for a property which was producing prior to the taxable year covered bj' the above statement the following information must be furnished.) Annual production of the tract or of the individual wells, if the lat- ter information is available, from the beginning of its productivity to the beginning of the taxable year for which the return was filed ; the average number of wells producing each year; and the initial daily production of each well ; and (?') Any other data which will be helpful in determining the reasonableness of the depletion deduction. MAPS. Maps that accompany records and delineate property boundaries must be sufficiently extended to show the position of property in rela- tion to section, township, and range lines, or in areas of metes and bounds survey, tlie relation to two or more established lines, of either township or district. On some part of the map should be recorded the name of the State, county, townsMp, or district, name of the company or individual rep- resenting property, scale of map, and date of survey, and points of the compass. It will be to the advantage of every taxpayer to assist the depart- ment in compiling complete statistics of all development that has taken place, and maps submitted should show location of all wells that have ever been drilled on a given property. The character of each well should be indicated by appropriate symbols. Where wells have been drilled by another company or individual it is advisable to distinguish such wells by some symbol or abbreviation, explaining the symbol in a marginal note. When a taxjoayer has filed adequate maps with the Commissioner he may be i-elieved of filing further maps of the same properties, pro- vided all additional information necessary for keeping the maps up to date is filed each year. This includes records of dry holes as well as producing wells, together with logs, depth, and thickness of sands, location of new wells, etc. By " production " is meant the net production of oil or gas belong- ing to the taxpayer. In those leases where no account is kept of the oil or gas used for fuel, the net production will necessarily be that remaining after the fuel used in the property has been taken out. In cases of this kind an estimate of the fuel used from each tract should be given for each year. 40 MANUAL FOR THE OIL AND GAS INDUSTEY. REVALUATION OF OIL OR GAS PROPERTIES DISCOVERED SINCE MARCH 1, 1913. Sections 214 (a) and 234 (a) of the Revenue Act of 1918, state— tliat in the case of mines, oil and gas wells, discovered by the taxpayer on or after Mai-ch 1, 1913, and not acquired as a result of purchase of a proven tract or lease, wliere the fair market value of the property Is materially dispropor- ti(]nate to the cost, the depletion allowance shall be based on the fair market value of the property at the rfate of the discovery or within 30 days thereafter; such reasonable allowance * * * to be made under rules and regulations to be prescribed by the Commissioner, with the approval of the Secretary. In the case of the leases the deductions allowed by this paragraph shall be equitably apportioned between the lessor and lessee. Extract from Eegulations 45 : A11TIC1T.E 220. Discovery of oil and gas icells. — In order to take advantage of his discovery on or after Jlarch 1, 1913, of oil and gas wells, the taxpayer must show (a) that the tract for wliich such valuation is claimed was not proven oil land as to the particular sand or zone discovery of which is claimed at the time the so-called discovery was made, proven oil land being that which has been shown by finished wells, supplemented by geologic data, to be such that other wells drilled thereon are practically certain to be commercial producers; (6) that the discovery wqs a bona fide discovery of a commercial well of oil or gas, or both of these substances, on the property in question, a commercial well being one whose production is such as to offer a reasonable expectation of at least returning the capital invested in such well through the sale of the oil or gas or both derived therefrom during the economic life; (c) that the fair market value of the property was materially In excess of the cost. AimcLE 221. Proof of discovery pf oil and gas wells. — In order to meet the requirements of the preceding article to the satisfaction of the Commissioner, the taxpayer will be required, among other things, to submit the following with his return: (o) A map of convenient scale, showing the location of the tract and discovery well in question and of the nearest producing well, and the de- velopment for a radius of at least 3 miles from the tract in question, both on tlie date of discovery and on the date when the fair market value was set; (b) a. certified copy of the log of the discovery well, showing (1) the. location, (2) the date drilling began, (3) the date of completion and beginning of pro- duction, (4) the formations penetrated and the oil, gas, and water sands pene- trated, (5) the casing record, including location of perforations, and any other information tending to show the condition of the well as to the location of the sand or sand from which the oil or gas came on the date the discovery was riainitcl ; (o) the logs of enough other wells drilled prior to the date of com- jilction of the discovery in the vicinity of the discovery well to convince the Commissioner that the sand or zone discovery of which is claimed was not known prior to the so-called discovery; {d) a sworn record of production, clearly iiroving the conunercial productivity of the discovery well; (e) a sworn y of the records, showing the cost of the property; and (/) a full explana- lion of llio method of determining the value on the date of discovery, or within .■^0 (lays thereafter, supported by satisfactory evidence of the fairness of this value. C0M5I1SS10XER's kuliko. The clause from sections 214 (a) and 234 (a) of the tax hiw re- ferred to above was inserted to protect the prospector or " wildcatter" who goes into an unknown field and overcoming hazards of the busi- ness discovers a new and valuable deposit of oil or gas, and by so doing increases the value of his holdings to such an extent that their value at the time of the discovery or within 30 days thereafter is ma- terially disproportionate to their cost. The discovery may refer to the opening up of a new pool or field or it may refer to the tapping of a new and previously unknown sand or zone in an old pool or field. The benefits, however, will accrue solely to the holdings of the tax- payer actually making the discovery. And it will affect him only in MANUAL FOE THE OIL A^TD GAS INDUSTRY. 41 SO far as he is able to prove that his discovery was bona fide, and that it has so increased the vahie of his holdings as to make it materially disproportionate to the cost. Unless the taxpayer proves to the satisfaction of the Commissioner that his so-called discovery well has opened up an entirely new pool or structure or a new sand or zone in the particular pool or structure in which the operation takes place, this law will not apply to (a) any tract or lease any part of which was proven or producing prior to the date of (the alleged) discovery, (h) nor to any tract or lease within the proven limits of any well-recognized oil or gas pool or field, (c) nor to such wells as are drilled immediately in advance of pro- ducing wells, (d) or on the edge of proven territory. Neither will it apply to the tract or lease of any other than the taxpayer making the bona fide discovery. The same evidence as required under " Determination of fair market value," pages 25 to 27, must be submitted by the taxpayer to substantiate the value which he sets up as of date of the discovery or within 30 days thereafter in the cases under discussion. (See Schedules I, II, and III, pp. 43, 47, and 51.) CHARGES TO CAPITAL AND TO EXPENSE IN THE CASE OF OIL AND GAS WELLS. Begulations 45, article 223. — Such incidental expenses as are paid for wages, fuel, repairs, hauling, etc., in connection with the explora- tion of property, drilling of wells, building pipe lines, and develop- ment of the property, may, at the option of the taxpayer, be deducted as an operating expense or charged to the capital sum returnable through depletion. If the taxpayer elects to charge such well and development costs to operating expenses, the amount so charged can not be included in invested capital on which excess-profits tax is com- puted, and the policy, once adopted, must be followed in subsequent years. If in exercising this option the taxpayer charges these incidental expenses to capital sum, in so far as such expense is represented by physical property, it may be taken into account in determining a reasonable allowance for depreciation. The cost of drilling non- productive wells may, at the option of the operator, be deducted from gross income as an operating expense or charged to capital sum returnable through depletion and depreciation as in the case of pro- ductive wells. The taxpayer should adopt a consistent policy as to capitalizing or charging off cost of drilling nonproductive wells. Casing-head gas contracts have been construed to be tangible assets and their cost may be added to the capital sum returnable through depletion, following the rate set by the oil or gas wells from which the gas is derived, or, if the life of the contract is shorter than the reasonable expectation of the life of the wells furnishing the gas, the capital invested in the contract may be vpritten off through yearly allowances equitably distributed over the life of the contract. All oil produced during the taxable year, whether sold or unsold, must be considered in the computation of the depletion allowance for the taxable year. However, oil on hand at the beginning and end of the year must, in computing net income, be inventoried at cost or estimated cost (including depletion or cost in the ground, plus lifting charges). 42 MANUAL FOR THii OIL AND GAS INDUSTKY. Wliere deductions for depreciation or depletion have eitlier on the books of the taxpayer or in his returns of net income been included in the past in expense or other accounts,, rather than specifically as depreciation or depletion, or \vhei*e capital expenditures have been charged to expense in lieu of depreciation or depletLon, a statement indicating the extent to which this practice has been carried should accompany the return. DEPLETION FOR PAST YEARS NOT ALLOWED BY DEPARTMENT. Where under the act of October 3, 1913, or of September 8, 1916, a taxpayer has not been allowed to make a deduction for the full amount of his depletion, the amount of such deficiency can not be carried forsvard and deducted in any later year. Depletion attaches to each unit of mineral or other property removed^ and a taxpayer should make proper provision therefor in computing his net income. Under the Eevenue Act of 1918 the amoimt recovecable through de- pletion will be the cost, or the value as of March 1, 1913, or within 30 days of the date of discovery, as the ca.se may be, less proper allow- ance for the mineral or other property removed prior to January 1, APPENDIX TO PART I. SCHEDULES. I. Schedule for Ascertaining Cost of Peopertx as of ant Specified Date. 1. Name of property. 2. Location of property. 3. Are you sole owner of property? i 4. If not sole owner, your ownership interest therein. 0. Is property a leasehold ? 6. (a) If so, name and address of lessor and lessee. (b) Date lease effective. (c) Date of expiration. (d) Eoyalty rate. (e) Bonus, either crtsh or property. 7. Date property was acquired. 8. (a) Manner of acquisition : (Purchase, trade, gift, etc.)' (h) Amount paid in cash. (c) Amount paid in stock. (1^ Par value of stock. (2) Actual cash value of stock. (3) How was this cash value established? (d) Amount paid in bonds. (1) Par value of bonds. (2) Actual cash value of bonds. (3) How was this cash value established? (e) Amount paid in other considerations. (1) What were the considerations? (2) State actual cash value of these considerations. (3) Manner of determining this cash value. (4) Name and address of party establishing value. (5) Append a copy of the report of the party establishing cash value of a resume of his report. (/) Cash value of total consideration paid for property as estab- lished by you. MAP. Map showing as of date of acquisition, location of the property, property boundaries, and location of all wells and other developments in this vicinity. This map must be on a convenient scale, preferably of not less than 1/31680 or 2 inches to the mile for developed areas, and should show the following information for each tract as of date of acquisition : (a) Wells producing. 43 44 MANUAL FOR THE OIL AND GAS INDUSTRY. (h) Wells temporarily suspended. (c) Wells formerly productive but now abandoned. (d) Wells completed to oil or gas sand or zone but nonproductive. ( c ) Wells abandoned before completion. (/) Wells drilling. (). (d) Average price per barrel received for oil, given by years since production began. (e) Total production prior to date of acquisition, in barrels. (/) Total production subsequent to date of acquisition, in barrels. (q) Total amount received for production mentioned in (e) and (/). {h) If the tract or wells have been producing for less than two years, monthly production figures must be furnished. 15. (a) Production of individual wells, by calendar years from beginning of production to date of acquisition, if such data are available. (b) Same information for period subsequent to date of acquisi- tion. {c) If, through any cause, it is impossible to give yearly produc- tion recoKcls by individual wells, state the reasons why this informa- tion is not available. OIL AND GAS KESEKVES IN rEOPERTT. 16. (a) What was the estimated total number of units of oil and/ or gas in the property on date of acquisition? (h) How was this estimate made? (c) Append a copy of the appraisal from which the estimates were derived or append a resume of the calculations utilized in mak- ing the estimate. (d) Give name and address of party making the estimate. 17. (a) State range in specific gravity of oil recovered. (&) State average specific gravity oil delivered. (c) If more than one grade delivered, give percentage of each for year of acquisition. CASING-HEAD GAS. 18. Submit table sho^ying— (a) Quantity of casing-head gas produced by months from date of first production to date of acquisition. (&) Quantity of casing-head gas produced by months for period subsequent to date of acquistion. (c) Average number of wells contributing to this production each ■year. (d) In case the gas is sold, give the amount received each month for gas mentioned in («) and (h). (e) Quantity of gasoline in gallons recovered each year from casing-head gas, mentioned in (a) and (6). (/) Amount received each month for gasoline mentioned in (e). {g') Average price per gallon received for gasoline mentioned in (e). (A) Production of oil by months for the wells from Avhich this casing-head - gas is taken. Give this information by individual 46 MAIfUAL FOR THE OIL AND GAS INDUSTRY. wells if possible; if not, then by tracts with number of wells produc- ing each month. When monthly records are not available give data by years. GAS -WELL DATA, f 19. Submit table giving list of gas wells as of date of acquisition, and showing — [,i) Number or letter by which each is designated. (h) Date of beginning drilling. (c) Date of beginning production. (d) Date of abandonment. (e) Initial open flow capacity. (/) Initial closed rock pressure. -, iff) Closed rock pressure as of date of acquisition. GAS-PRODUTION DATA. I t 20. Submit table showing — (a) Gross production (of gns) by calendar years, from beginning of production to date of acijuisilion, with number of wells producing each year. (b) Same information for years subsequent to date of acquisition. (c) Amount of money and cash value of any other consideration recoived each year for production mentioned in (a) and (i). (d) Average price per thousand cubic feet of gas, by years from beginning of production. (e) Total yield from beginning production to date of acquisition, in cubic feet. (/) Total yield from beginning production to date, in cubic feet 21. Production of individual wells by calendar years for all wells to end of taxable year. 22. (a) Average rock pressure in September of each year during which production has been maintained. (^>) Kock pressure of individual or test wells on tract. (Answers should be attached as a separate statement giving all rock pressures measured during life of the well or property. The method used in measuring pressures should be mentioned.) PHYSICAL pi;01"Ei;ty. 23. Does the cost of property as given in S (f) of this schedule in- clude any amount for plant or other physical property or for the value of the land for any other purpose than that as container of oil and gas? 21. If it does, what amount is applicable solely — (a) To the value of the oil and gas contents? (b) To the surface or agricultural value of the land or its value for anything other than for its oil and gas contents? (c) To plant or other physical property? 2:"). Give general inventory as of dato of acquisition of the physical property mentioned in 24 (c) with the following information regard- ing each type : (o) Year originally acquired. MANUAL TOR THE OIL AND GAS INDUSTRY. 47 (6) Original cost. (c) Depreciation sustained to date of acquisition. (d) Estimated cost as of date of acquisition. II. Schedule foe the Valuation of Property as of any Specified Date. Introduction. — In actually determining the fair market value of au}^ property as of any specified date it will be necessary in most instances to require very full data regarding the property in order that no factors having a bearing on the value may be overlooked. The following information as of the specified date of appraisal will usually be required of the taxpayer in order to substantiate his appraisal. Note. — "Date of appraisal" is the speclflecl date as to wUicli the valiialiou is set up and is not tlie date on which the appraisal is made. 1. Descri2^tion of the jyTcperty. — (a) A legal description of the propertj^, including its location in section (or farm), township, range, county, and State. {h) AA'hether or not the taxpayer is the sole owner; and if not, his ownership interest therein and the names and addresses and owner- ship interest of each of the other joint owners. (o) Whether the jDroperty is a leasehold; if so, the name and ad- dress of the lessor and lessee. ((?) The date lease was effective. ' \e) Date of expiration. (/) Eoyalty rate. Ig') Bonus, either cash or propert}^ (7i) Any unusual terms of lease. 2. Date of acquisition. — The date the property was acquired. 3. Manner of acquisition and cost. — (a) The manner of acquisition of the property, whether by purchase, trade, gift, etc. (h) The amount of the consideration paid, such as cash, stock, bonds, etc., and the cash value of these, and how this cash value was determined. 4. Map of property. — A map of the property on a convenient scale, preferably not less than 2 inches to the mile, showing as of date of appraisal — [a) The producing, suspended, or abandoned, and drilling wells, and (6) The area of the tract which is considered producing, proven, highly probable, possible, or worthless oil or gas land. In the case of a taxpayer owning more than one tract in a single pool or field, a field map may be substituted for maps of each tract, the tracts or leases being designated by letter or some other symbol. 5. La7id data. — A statement as to the number of acres considered fully developed, proven, highly probable, possible, or worthless oil or gas territory, including the total acreage, and the name and address of the party making such classification. 6. Well data. — (a) Information as to the number of wells produc- ing, abandoned, or suspended, drilling and the number of locations remaining undrilled on proven territory. 48 MANUAL FOE THE OIL AND GAS INDUSTRY. (h) The number and designation of the oil or gas sands proven on the property, with their average thickness and the average depth from the surface to the top of each sand. 7. Individual veil data. — The following information regarding the individual wells: (a) The liumber of the well. (6) Date began drilling. (f ) Date began producing. (d) Date abandoned. (e) Initial daily production. 8. Production data. — (a) The production of each tract by calendar years for the periods prior to and subsequent to the date of ap- praisal. {b) The average number of wells producing- each year. (c) The amount received each year for the production. {d) The average price per barrel received each year. {c) The total production prior to and subsequent to date of ap- praisal. (/) The total amount received prior to and subsequent to the date of valuation. "\Miere production figures of individual wells are available, give the records for all years from the begimaing of production to the date of valuation, and for the years subsequent thereto. In the case of properties yielding production for a period of less than two years, the above data should be given by months instead of years. t'. Oil and gas reserves. — {a) The estimated total number of units of oil or gas in the property as of the date of appraisal. (Many o])erators are prone to say it is impossible to estimate the quantity of oil or g!ih under any tract — obviously it is impossible to determine this exactly — but it can he done with reasonable accuracy in most in- stances.) (b) How this estimate was made. ((■) The name and address of the party making the estimate, and a copy or resume of his report. 10. Specific gravifij.— {a) The range in specific gravity of the oil recovered. (b) The average specific gravity of the oil delivei-ed, and, if more than one grade is delivered, the percentage of each delivered during the year covered by the appraisal. 11. Casing -head gas. — The following information by months: (a) The quantity, in thousands of cubic feet, produced prior to and subsequent to the date of appraisal. lb) The number of wells producing this gas. (c) The amount received for the gas, if such was sold direct. {(l) The quantity, in gallons, of gasoline made. {e) Tlie amount received for this gasoline. (/) Tlie average price per gallon. (g) The production of oil by months for the wells yielding the g;iK covered by this paragraph. I'i. Gas properties. — In the case of gas properties the well data sliould include: (a) The number of each well. (&) Date began drilling. MANUAL FOE THE OIL AND GAS INDUSTRY. 49 (c) Date began producing. (d) Date abandoned. (e) Initial daily capacity. (/) The initial closed rock pressure. (g) Present closed rock pressure. The production data are to be given by calendar years prior to and subsequent to date of appraisal. (fi) Number of wells producing. (?>) The value of the product and the average price per thousand feet. (c) The total yield (1) prior to and (2) subsequent to the date of appraisal. (d) The gross production of individual wells by calendar years to date. (e) The average rock pressure during September of each year during which production has been maintained, and as many records as possible of the rock pressure of individual or test wells. DIRECT METHODS OF DETERMINING VALUE. 13. The points to be considered directly in the establishment of a fair market value must include the method by which this value was ascertained. {a) Whether established by cost. (6) By comparison with values established by actual sales of similar properties. (c) By appraisal. (d) By assessed value. (e) By any other method. 14. If the value is based upon the values of other properties, as established through the transfer of the properties, details regarding each transaction will be necessary. Furthermore, it will be advisable to give information regarding any bona fide transactions in oil or gas properties in the region of the tract under appraisal about which the taxpayer is able to obtain data, this information to include as many of the items called for in connection with the valuation of the property itself as it is possible to secure. 15. If the value is established by appraisal give — (a) The name and address of the party making the appraisal. (5) His connection, if any, with the taxpayer or with any of his associates or associated companies. (c) The date of making the appraisal. (d) A copy of the appraisal or a resume. 16. If the value is established by assessed valuation, the following should be given : (a) Name and address of official making the assessment. (6) Whether it was assessed at its actual cash value or at a por- tion of its cash value. (c) What its total assessed valuation was in the year in which the appraisal was made. (d) What portion of the assessed valuation represents real prop- erty? (e) What portion represents personal property. llloeo°— 19 4 50 MANUAL FOR THE OIL AND GAS INDUSTRY. (/) Wliat portion of the assessed value of the real property repre- sents oil or gas in the ground ? 17. If the values are established by any other method than the abo^■e a full description of the method used and conclusions reached should be given. 18. If the valuation of tlie property includes any araount for plant or other physical property, or for the surface or agricultural value of the- land, or the value of the land for any other purpose than as a container of oil and gas, the value sliould be segregated under the headings : (a) Value of oil and gas contents. (b) Values for anything other than for oil and gas contents. (c) Value of plant or other physical equipment. 19. An inventory of the physical equipment as of the date of ap- praisal should be given, together with the following information regarding each type of property : (a) When the equipment was first used. (h) Its cost. (c) Its total depreciation up to the date of appraisal. (d) Its value as of the date of appraisal. (e) Depreciation by calendar years for each year subsequent to the date of appraisal. The classification of physical equipment will be found under the chapter on depreciation, page 64 of this Manual. IXDIRECT 3IET1I0DS OF DETERMIXIXG VALUE. 20. The book value of the total assets on the date of valuation ex- clusive of oil or gas in the ground. 21. (a) The number, par value, and cash value of the shares of capital stock issued and outstanding on the date of appraisal. (J) Whether or not these outstanding shares were fully paid. (e) Information as to what stock exchange or "curb" market the stock or bonds were listed on, or dealt in, on or about the date of appraisal; or if the stocks were not quoted publicly, particulars re- garding private transactions in the stock or bonds on or about the date of apprnisal. 22. Total permanent indebtedness classified as bonds, notes, con- tracts, etc., and what the quoted value of these securities was or any particulars regarding public or private transactions which would tend to establish their value. 2:1 The prevailing average royalty rates stipulated in leases taken within a year of the date of appraisal in the district in which the property is located. 24. Copy of the report to the stockholders of the company for each of the fiscal years preceding and following the date of appraisal. 25. So far as known, the names of the parties to any litigation in which the value of the oil and/or gas properties in the particular region of the property under discussion, or of a partnership interest or other interest therein, or of stock in a corporation owning or operating the same, was involved; also, the name of the court or courts in which such litigation was conducted. 26. If the value of the oil and/or gas wells in the particular reo-jon of the property, or of any interest or stock therein has been involved MANUAL FOR THJil OIL AND GAS INDUSTRY, 51 in any partnership accoimting known, a statement regarding such accounting should be given. 27. If anyone interested in the oU and/or gas wells in the par- ticular region of the property under discussion or as owner, opera- tor, or member of a partnership, or stockholder in a corporation ow^ing or operating the same died on or about the date of appraisal, give the name, number of shares held, the approximate date of death, the residence at time of death, and the name and location of the court in which the estate was administered, and the name and address of the administrator. 28. In addition to the above the taxpayer is requested to submit- any other evidence, facts, statements, etc., which he desires to have considered in the determination of the value as of the date of appraisal. III. Schedule for Peoof of Discovert. Introduction. — In order to prove to the satisfaction of the Com- missioner that a bona fide discovery of oil or gas in commercial quan- tities has been made, the taxpayer will be required, among other things, to submit the following, under oath : 1. Description of the property. — (a) A legal description of the property, including its location in section (or farm), township, range, county, and State. (b) Whether or not the taxpayer is the sole owner, and if not, his ownership interest thei'ein, and the names and addresses and owner- ship interest of each of the other joint owners. (c) Whether the property is a leasehold; if so, the name and ad- dress of the lessor and lessee. (d) The date lease was effective. (e) Date of expiration. (/) Eoyalty rate. (ff) Bonus, either cash or property. (A) Any unusual terms of lease. 2. Date of acquisition. 3. The location of the nearest producing well to the discovery well on the date discovery is claimed. 4. Map of property. — A map of the property on a convenient scale, preferably not less than 2 inches to the mile, showing, as of the date of discovery, (a) the location of the tract and of the discovery well in question and in addition the development in the field for a radius of approximately 3 miles from the well in question ; (&) The producing, suspended or abandoned and drilling wells; and (c) The areas which are considered producing, proven, highly probable, possible, or worthless oil or gas land. 5. A certified copy of the log of the discovery well, showing: (a) The location^ (h) Date drilling began, date of completion and the beginning of production. (e) The formations- penetrated; the oil, gas, and water sands pene- trated ; the casing record, including the record of perforation and any otlaer information tending to show the condition of the well and 52 MANUAL FOE THE OIL AND GAS INDUSTKY. the location of the sand or sands from which the oil or gas came on the date the discovery was claimed. 6. The logs of enough other wells drilled prior to the date of com- pletion of the discovery in the vicinity of the discovery well to con- vince the Commissioner that the pool, field, structure, sand, or zone, discovery of which is claimed, was not known prior to the so-called discovery. 7. A sworn record clearly proving the commercial productivity of the discovery well. This record must cover a period of not less than 30 days and, if possible, should include the production of the entire period by months from the date of discovery to the end of the first year. 8. In the case of the discovery being made within 3 miles of pro- ducing wells, the production data from enough wells within this area to indicate the average productivity of the wells drilled prior to the date of drilling the discovery well. 0. The specific gravity of: (a) The oil recovered from the discovery well. (i) Oil produced by adjacent wells which were producing at the time of the drilling of the discovery well. 10. The following information regarding wells drilled on the same tract or lease as the discovery well prior to and subsequent to the date of the discovery : (a) Number of well. (b) Date of beginning drilling. (c) Date of beginning production. (d) Date abandoned. (p) Initial daily production. And in the case of wells drilled prior to the date of discovery — (/) Copy of the log of the well, including the formations pene- trated. (g) The casing record and any other information tending to show the condition of the well on the date discovery was claimed in the discovery well. 11. Any other evidence, facts, statements, etc., which the taxpayer desires to have considered as proving that the so-called discovery is bona fide and that the pool, field, structure, sand, or zone, discovery of which is claimed, was not known prior to the date of discovery. IV. Schedule tor Depletion. With respect to each property producing oil and/or gas during the taxable year for which the return under consideration was filed, trive the following facts: 1. Description of property. 2. Value (exclusive of physical properties) as of March 1, 1913, o)' its cost if acquired subsequent to that date. 3. Estimated quantity of oil and/or gas in ground as of March 1, :1913. or at date of acquisition if secured subsequent to March 1, 1913. 4. Make tabulation showing: (a) Capital sum returnable through depletion at besinnino- of year. ^ (b) Capital returnable through depletion added during year. MANUAL FOR THE OIL AND GAS INDUSTRY. 53 (c) Total capital sura against which depletion for year is chargeable {{a) plus (b)). (d) Estimated quantity of recoverable crude oil in ground at be- ginning of year, in barrels of 42 gallons. (e) Production for year in barrels of 42 gallons. (f) Unit cost of recoverable product ((c) divided by (d)). (g) Amount of depletion sustained during year ((/) multiplied by (e)). V. Schedule for Depeeciation. With respect to each tract on which there is physical property men- tioned in the return under consideration, give the following facts : 1. Description of property. 2. Value of physical properties as of March 1, 1913, or their cost, if acquired subsequent to that date. 3. Make tabulation showing: (a) Capital sum returnable through depreciation at beginning of year. (&) Capital returnable through depreciation added during year. (c) Total capital sum against which depreciation for year is chargeable (a plus 5). (d) Amount of depreciation sustained during year. VI. Schedule foe the Peoof of Bona Fide Sale. Introduction. — To prove that the sale consummated by the tax- payer is actually bona fide, he will be required to furnish a sworn statement, including the following : 1. Desci-iption of tlie property. — {a) A legal description of the property, including its location in section (or farm), township, range, county, and State. (b) Whether or not the taxpayer is the sole owner, and if not, his ownership interest therein, and the names and addresses and owner- ship interest of each of the other joint owners. (c) Whether the property is a leasehold; if so, the name and address of the lessor and of the lessee. {d) The date lease was effective. (e) Date of expiration. (/) Royalty rate. {g) Bonus, either cash or property. (A) Any unusual terms of lease. 2. Date of disposal of property. 3. Manner of disposal of the property. — Whether by sale, trade, gift, etc. 4. {a) The amount received in cash, stock, bonds, and other con- siderations. (&) .The par value of the stock, bonds, or other considerations. Note. — If the " unit-cost " method of computing depletion was not use3 In computing the depletion allowance for the various yeai-s mentioned in the above table, state what method was used in calculating the depletion, and give a complete rfisumg of the calcula- tions, so that the Commissioner may arrive at an intelligent conclusion as to whether or not the depletion allowance claimed for the year was equitable and based on the actual production of that year. 54 MANUAL FOE THE OIL AND GAS INDUSTRY. _ (e) The actual cash value of the stock, bonds, or other considera- tions on the date of disposal of the property. (d) How these cash values were established. i. i t t, (e) The name and address of the party determining or establLSh- ing these values. 5. Total cash value of all considerations received by the taxpayer for the property. G. (a) The name and address of the party to whom the property Wtis trcirisf6rr6ci- (&) The connection, business or other, if any, between parties to 7. The taxpayer disposing of the property will be required, under oath, to state whether or not the price at which the property was sold was fixed for the purpose of a bona fide purchase and sale by which the property passed to an owner in fact as well as in form different from the vendor. No fictitious nor inflated sale price will be permitted to form the basis for the price established for this schedule. 8. Any evidence, facts, statements, etc., which the taxpayer desires to have considered as a proof in the determination of the bona fide character of the transaction. VII. Schedule for Computation- of PRorrrs or Loss from Sale of Capital Assets. With respect to each property disposed of during the year, furnish the following information: 1. Description of property. 2. Date of disposal of pro2)erty. 3. Manner of disposal of the property (sale, trade, gift, etc.). 4. Amount received in cash. 6. Amount received in stock: (a) Par value of stock. (b) Actual cash value o (c) How was this cash value established? 6. Amount received in bonds : (a) Par value of bonds. (b) Actual cash value of bonds. (c) How was this cash value established? 7. Amount received in other considerations: (a) AMiat were these considerations? (b) Actual cash value of these considerations. (c) Manner of determining this cash value. (d) Name and address of the party determining this vahie. 8. Cash value of all considerations received for property. 9. Value of property as of March 1, 1913, or its cost if acquired subsequent to that date. 10. Total of all additions to capital returnable through depletion added subsequent to March 1, 1913, or ubsequent to date of acquisi- tion if property acquired subsequent to March 1, 1913. 11. Total of all additions to capital returnable through deprecia- tion added subsequent to March 1, 1913, or subsequent to date of acquisition if acquired subsequent to March 1, 1913. MANUAL, rOK THE OIL AND GAS INDUSTRY. 55 12. Gross value of property as of date of disposition. (Total 9, 10, and 11.) 13. Total depletion sustained during period from March 1, 1913, or from date oi acquisition if acquired subsequent to March 1, 1913, to date of disposition of property. 14. Total depreciation sustained during period from March 1, 1913, to date of disposition of property. 15. Net value of property as of date of disposition of property (12 less the sum of 13 and 14). 16. Profit or loss sustained from disposition of 'property (Difference between 8 and 15). VIII. Schedule for Proving that the Principal Value Has Been Demonstrated by Prospecting or Exploration and Discovery Work Done by the Taxpayer. Introduction. — ^In the case of a bona fide sale of oil or gas proper- ties it will be necessary, in order to secure the benefits of sections 211b and 337 of the Eevenue Act of 1918, which limits the portion of the surtax imposed by said act attributable to such sale to a sum not to exceed 20 per cent of the selling price of such property or interest, to satisfy the commissioner that the principal value of the property has been demonstrated by prospecting or exploration and discovery work done by the taxpayer by submitting the following among other data: 1. Desmption of the property. — (a) A legal description of the property, including its location in section (or farm), township, range, county, and State. (&) Whether or not the taxpayer is the sole owner, and if not, his ownership interest therein, and the names and addresses and owner- ship interest of each of the other joint owners. (c) Whether the property is a leasehold; if so, the name and ad- dress of the lessor and lessee. (d) The date lease was effective. (e) Date of expiration. (/) Koyalty rate. Cg) Bonus, either cash or property. (A) Any unusual terms of lease. 2. The value of the property immediately prior to the date of he- ginning the prospecting or exploration and discovery xoorh done hy the taxpayer leading to the discovery claimed. — (This may be estab- lished through filling out Schedule II as of the specified date.) 3. The proof that a discovery has heen made. — (To furnish this proof the taxpayer will be required to fill out Schedule III.) 4. The value of the property at any specified date within a rea- sonable time after the discovery was made. — (This value may be established by tilling out Schedule II for the specified date.) 6. Any evidence, facts, statements, etc., which the taxpayer desires to have considered as showing that the principal value of the prop- erty has been demonstrated by prospecting or exploration and dis- covery work done by himself. PART II. ESTIMATE OF DEPRECIATION OF EQUIPMENT USED IN THE OIL AND GAS INDUSTRY. PREFACE TO PART II. This chapter is a condensation and summarization of the conclu- sions of a committee appointed to investigate and standardize depre- ciation allowances in the case of oil and gas properties. It is pre- ])ared to meet the questions of taxpayers as to what is a reason- able allowance for depreciation in the case of oil and gas properties. In preparing the figures of rates of depreciation, reports from some of the larger companies were reviewed and the opinions of various individuals closely associated with the industry were obtained. Over 60 companies and individuals were canvassed in this work and the conclusions were reached by considering the company practices as well as taking into account the experience of the members of the com- mittee and the precedents and practices of the Treasury Department. The pcrcenlagcs and tables included in this paper are intended as a sKffgestion for the guidance of the taxpayer in calculating his just tax. The percentages are neither maximum nor minimum rates. They are not to be applied indiscrinunateJy to specific property, and tile Internal Eevenue Bureau is in no way committed to accept allow- ances based upon them. Every claim for deduction must be accom- panied by a detailed statement of the facts upon which such claim is based. Each class of ccjuipment is shown in detail and as a class, with the suggestion that an average life of the class be used rather than going into the details of every part. The average years of useful life of the various classes is shown in the summary sheet and a suggestion for charging out annual per- centages to conform to the depreciation as it actually occurs. It must be borne in mind that it is not possible to make standard rules or formulte to cover all conditions in this business. Although different rates may reasonably be applied in different ])arts of the country, the average rates for each locality have not been included here, as it is believed that the variation of such rates from the general average is so slight as to be practicallj' negligible in most instances. Whenever the life of the property is materially shorter than that called for in this scliedule, a special rate may be claimed, or the differences may be made up by replacements chargeable to the maintenance accounts. In the case of some of the Gulf coast districts, portions of the pipe lines are eaten out in five or six years. These repairs are rightly a replacement and chargeable to maintenance or operating accounts. 56 •MANUAL FOR THE OIL AND GAS INDUSTRY. 57 Depreciation deductions are to be charged to a reserve fund, and are in addition to any regular charge for repairs and operating maintenance. No consideration has been given exceptional cases where prema- ture failure of supply or market may materially reduce the given life of the facility. Such cases are necessarily exceptional and will receive special consideration, as provided for in the regulations. (See Regulation 45, Art. 225.) CLASS A, NO. 1.— DRILLING EQUIPMENT. This includes engines, boilers, rig irons, and portable derricks. It is recommended that four years' life be allowed to equipment as a whole, depreciated at the following rate: Per cent. First year 40 Second year ; 25 Third year ^ 15 Pourtli year_^ 10 90 Salvage 10 100 Permanent derricks, rig irons, boilers, and engines left at the well are included under " Well equipment." Drilling tools (cable and rotary), and fishing tools are included under "Tools "—Class A-No. 5. CLASS A, NO. 2.— WELL EQUIPMENT. As most equipment of a producing well has no separate value apart from the well, it is suggested that all wells and their equipment be depreciated at the same rate as the wells are depleted, using the same curve rate for both or where the life of the physical equipment is greater than the life of the deposit, then the depreciation rate of the physical equipment will be governed by the reasonable expecta- tion of the life of the deposit. When the life of the equipment is shorter than the life of the well, replaced equipment should be charged against maintenance and operation. This method ^proved satisfactory in the appraisements of the Inde- pendent Oil Producers Agency of California, embracing some 130 companies, and is generally acceptable to all operators who have been consulted in the matter. CLASS A, NO. 3.— DEHYDRATORS. These are either of electric, pipe, or tank type. The life of the pipe and tank dehydrators is very erratic as these burn out quickly with practically no salvage. It is recommended that this type of equipment have a straight line depreciation as follows: 58 MANUAL FOR THE OIL. AND GAS INDUSTRY. Electric Pipe... Tank. . . CLASS A, NO. 4.— TANKS. The following depreciation rate for tanks is recommended: Steol, .5,000 to 53,000 barrels Steel, 2,rM to 5,000 barrels G. I., 500 to 2,500 barrels 0. 1., loss than 500 barrels Wood Movable tanks: 0. 1., 500 to 2,500 barrels G. I. , less than 500 barrels G. I., water tanks, 500 to 2,500 barrels.. G. I., water tanks, less than 500 barrels Per cent. 5 8J 20 These results may be used for all classes of service- ducing, refineries, etc. CLASS A, NO. 5.— TOOLS. -that is, oil pro- This includes standard, rotary, and fishing tools. While rotary equipment may be shorter lived, it is, in general, offset by the standard tool equipment which will have a life of at least four years in many cases. Owing to the excessive wear and tear and losses on such equipment an average life of three yeai"s is recommended, using an annual de- preciation of 33J per cent. CLASS A, NO. 6.— TUANSPORTATION EQUIPMENT. All transportation equipment, such as motor trucks, autos, wagons, horses, and harness, can be placed at a three-year life or an annual depreciation of 33J per cent. In fact, the average life of automobiles is less than three years. TliG percentages of cost for horses, harness, and wagons is such that the whole can be made one class with three years' life and consider no salvage. CLASS A, NO. 7.— WATER PLANTS. Considering the water well, pump, steam power, gas and oil power, electric power as a class, they may be given a useful life of approxi- mately 10 years, which allows a straight depreciation of 10 per cent. CLASS A, NO. 8.— ELECTRIC EQUIPMENT. In considering electrical equipment, one may include the separate items of generators, various size motors, transformers, wiring (both indoor and outdoor), power lines, and switchboard. '' MANUAL FOR THE OIL AND GAS INDUSTRY. 59 As oil-well motors are not suitable for other uses and as the class of wiring usually done on leases is not up to utility company standards, it is recommended that a combined life on electric equipment be placed at 10 years, or an annual depreciation of 10 per cent. CLASS A, NO. 9.— MACHINE SHOP. In covering machine shop there is included wood buildings, power tools, blacksmith tools, small hand tools, shafting, and shop power, which will, on an average, have a seven-year life or a depreciation rate of 14f per cent. The smaller hand tools, of course, may have a life of not more than two years, but their cost is not important and the depreciation rate is lowered by the longer life of more ex- pensive items, such as power tools, wood buildings, shafting, and shop power. CLASS A, NO. 10.— BUILDINGS. Buildings are grouped into four general classes: No. 1. Wood, which includes small dwellings, small outhouses, small warehouses, small power plants, and small platforms which are built on the ground. These have an average life of 10 years, which allows a depreciation rate of 10 per cent. No. 2. Frame buildings, placed on brick or concrete foundation with siding and shingle or patent roof painted, have an average life of 15 years or a straight line depreciation of 6|- per cent. No. 3. Corrugated iron siding, renewable, has a life of six years or a depreciation rate of 16|- per cent. No. 4. Concrete, brick, and steel frame have an average life of 25 years or an annual depreciation rate of 4 per cent. The permanent buildings may outlast the remainder of the plant ; hence, no salvage value. Gulf Coast fields may claim shorter life on account of salt air conditions. CLASS B.— PIPE LINES. Pipe lines are subdivided into main line, pump stations (which include all equipment such as engines, pumps, boilers, etc.), auxili- ary equipment, buildings, telephone and telegraph, and terminal facilities. It is recommended that— Mains 6 inches in diameter or over be based on a 20-year life or an annual depreciation of 5 per cent. Mains under 6 inches diameter be based on a 16-year life or an annual depreciation of 6^ per cent. Gathering lines be based on a 10-year life or an annual deprecia- tion of 10 per cent, with a salvage of 10 per cent. Pump stations, including all equipment, telephone lines, and ter- minal facilities a life of 10 years, or an annual depreciation of 10 per cent. These conclusions were reached after carefully considering de- tailed data in which it was decided that pipe lines could be grouped into the subdivisions given above. The subject of electrolysis in pipe lines has been investigated and the losses have proved to be very small and negligible in comparison 60 MANUAL FOR THE OIL AND GAS INDUSTRY. with the amounts invested, so far as making any special allowances in depreciation. ., , ^ • 10 Below is given the result of a pipe line 220 miles long, having 16 stations and costing $3,906,668. Right of way. Ditching Pipe Steol storage.. Buildings Total... Machinery: Pumps Boilers Heaters Miscellaneous (freight, etc.). Total. Wiring Fittings Commissary Telephone lines Spurs, loading raclcs, etc Sundries (tools, paints, water wells, etc., superintendence super- vision) Total <:rand total cost. Per cent of total life in- Weight. cest. Years. $83,176 497,358 1,323,901 428,047 246,651 2.2 12,7 33.9 10.9 6.3 20 ■20 20 20 20 0.44 2.54 6.78 2.18 1.26 2,577,133 260, 108 136,358 30,341 88,937 - 6.7 3.5 .8 2 3 14 10 10 8 .94 .39 .08 .18 515,742 8,060 151,725 270,782 85,905 14,276 283,045 .2 3.9 6.9 2.2 .4 7.2 10 ■7 10 10 5 5 ,02 .27 .09 .22 .02 .36 1,329,535 100.1 •16.33 3,906,688 ' Same as pipe. ' Average life. CLASS C— TANK CARS. This class of equipment is of very stable construction, and it would appear that the maximum 20-ypar life can be accorded and a 5 per cent per annum deiDreciation established. CLASS C— REFINERIES. Tn order to arrive at a depreciation figure for the refinery as a wliole, it is necessary to determine the relative investment in each item of equipment as compared to total investment. The various items haAe been grouped into classes that have about the same rate of depreciation, and the depreciation for the whole plant calculated by multiplying each item by its rate of depreciation. Refineries were di\idod into two classes, skimming plants and com- plete refineries — that is, refineries equipped with lubricating plants (but not having cracking plants). Figures for relative investment in each cla8.s of equipment were obtained from reports on valuation of refineries and from our own estimates. •MANUAL FOR THE OIL AND GAS INDUSTRY. 61 Calculated depreciation for whole refinery. (0) COMPLETE REFINERY. Per cent of total invest- ment. Rate of de- preciation. Product. Equipment: Distilling equipment (stills, condensers, agitators, etc.) , Power plant (boilers, engines, electrical equipment, etc.) Buildings Storage (all kinds) Pipes and fittings ." Lubricating plant (filters, presses, chillers, grease plant, etc.) . . . Miscellaneous (* * * loading racks, machine shop, labora- tory, etc.) Per cent. 25 15 10 25 10 10 Per cent. 15 10 5 8 12 10 Depreciation on refinery as a whole. Per cent. 3.8 1.5 .5 2.0 1.2 1.0 10.5 (6) SKIMMING PLANT. Distilling equipment - Power plant Buildings Storage Pipes and fittings Miscellaneous Depreciation on refinery as a whole. Per cent. 35 10 5 35 10 5 Per cent. 15 10 10 Per cent. 5.3 1.0 .5 2.8 1.2 .5 11.3 Eefineries can also be classed according to their location into three general classes and should be given rates of depreciation accordingly. The three classes and suggested relatire depreciation are as follows: Well-constructed refinery plants located on the Atlantic coast or Gulf coast or at points that are assured'of a supply so long as there is production east of the Rocky Mountains or from Mexico Refinery plants of good construction located on trunk pipe lines or where a supply of crude is assured for several years Skimming plants and small refineries of poor construction or located at points where the supply of crude is not assured for a long period of time Deprecia- tion rate. Per cent. 5 10 163 It is suggested that the last named be depreciated according to the decline curve of the oil field supplying the oil. The estimates of the total depreciation Avere based on what was considered the normal life of the plant, and no conditions that were purely local were taken into consideration. He ./ever, in making any depreciation charge the relation of the location must be taken into account. Such things as the supply of raw material, removal of market, climatic conditions, soil conditions, and the nature of the raw material are points brought out by local conditions. Plants situated on pipe-line terminals and those on the seaboard that can be fed by tankers and pipe lines have an advantageous position. Plants in the midst of an oil field relying solely on that field for crude supply have a length of life depending on the life of the field. Plants on pipe lines controlled completely or in part by the company owning the plant are in much better shape than those dependent on a rival company for their supply of crude. 62 MANUAL FOR THE OIL AND GAS INDUSTRY. A plant is subject to the removal of its market in whole or in part when it is situated a great distance from that market and is con- fronted with a new plant or competitor adjacent to the market that is able to undersell the products of the distant plant. The foreign market may be completely removed through the growth of new oil fields and competitive tariff conditions. Any abnormal rate of depreciation due to the chemical nature of the soil causing ironwork to deteriorate rajDidly must be considered. Conditions of high humidity shorten the life of ironwork and brick- work. High sulphur crudes cause stills and condensers to deteriorate rapidly. Crudes containing salt, other solid or colloidal matter and those carrying a high content of water and foreign matter cause a shorter life for general refinery equipment. An agreement must be reached between the Treasury Department and the refiners in cases for special districts as to just how much extra depreciation they should be allowed for a condition that is peculiar to their territory. The total general depreciation that is allowed takes in the skim- ming plants and so-called complete refineries that have a lubricating plant. For plants that have a complete refinery and in addition cracking plant, certain extra depreciation diarges must be allowed. In many cases the cracking plant is as much as one-tenth the total plant investment and should be given a shorter life than the average plant's life. CLASS D— SALES OR MARKETING EQUIPMENT. Sales or marketing equipment is summarized in the following table : Annua! deprecia- tion rate. Tankers: Where sirh have been bought or built durin? the war period, that such cost be \vrittenofIto$125per P. W. ton and at that rate , Bar?cs, harbor tuss, or other small floating equipment FilKn? stations; ( 1 ) Ordinary wood or corru'?ated constru"t ion (2) Brick and concrete, or extraordinary construction Distributing stations Tank wagons: Motor type Horse type Steei barieis Tracks and switches In considering depreciation on filling stations the factor to be given the most consideration is location. The normal life of equip- ment and buildings is at least 10 years, but unless the station is favorably situated it may only last 2 or 3 years. XoTE. — Filling stations are divided into two classes: (a) Stations that have temporary wooden or corrugated iron buildings; and (b) stations that have buildings of brick or terra cotta, where the invest- ment in buildings represents a large i^ercentage of the total invest- ment. MANUAL, FOE THE OIL AND GAS INDUSTRY. 63 Distributing stations with exception of delivery equipment do not depend to such a large extent on location, and lor that reason are given a longer life, although if delivery equipment is taken into consideration the depreciation rate for the whole plant would no doubt be higher than for filling stations. Delivery equipment, such as tank wagons, horses, trucks, etc., constitute a large percentage of the investment in distributing stations and are short lived; there- fore, in calculating depreciation on distributing stations the relative investment in warehouse equipment and in delivery equipment must be taken into consideration. The rate of depreciation on tank cars is the same as that given under refinery equipment. The investment in tank cars is really a special item Avhen considering sales equipment as a large number of marketers do not own any tank cars at all. The same thing applies to marine equipment, since only the large companies that do an extensive export business possess marine equip- ment. It is believed that an average depreciation rate of 10 per cent or a life of 10 years will cover this class of equipment, since equip- ment such as bulkheads, docks, etc., have a life of only 4 to 6 years, while floating equipment, such as tankers, will easily last 20 years. CLASS E— NATURAL GAS— UTILITY COMPANIES. The drilling equipment and well equipment of natural gas com- panies should be depreciated at the same rate as drilling equipment and well equipment for oil wells, previously given. The following depreciation rate is suggested for gas-pipe lines: Per cent. Mains 8i Gathering lines 10 City lines 10 Compressor stations, including gas compressors, engines, boilers and equip- ment, should be grouped into one heading and depreciated at an an- nual rate of . 14r Gathering stations 16 j Field stations 25 Meters and regulators 20 The information at hand in which the cost of the equipment was taken into account showed that a natural gas plant could be depre- ciated, as a whole, at a rate of 10 per cent. It is a general consensus of opinion that the average life would not be over 10 years. It is recommended that conditions existing on January 1, 1916, be used as a basis, and that all expenses incurred to maintain the- output or carrying capacity of lines, as of that date, be treated as follows : That intangible expenses may be charged direct to maintenance as an operating expense. That tangible items be charged to investment or capital account and should be given a 25 per cent salvage value and the remaining 75 per cent charged off at the rate of 174 per cent per annum for all gas properties other than those in West Virginia, Pennsylvania, and possibly Ohio, where the natural gas plants, as a whole, should be given a 15-year life, and the extensions figured on a 7-year life on a 15 per cent salvage, and the remainder charged off at the rate of 12 per cent per annum. 64 MANUAL FOR THE OIL AND GAS INDUSTRY. The above conclusions are based upon a 7-.year life for gas fields in West Virginia, Pennsylvania, and possibly certain portions of Ohio, and on a 4-year life for all other gas fields. The shorter life for the other gas fields can be substantiated by numerous examples, such as Southern Kansas, Hogshooter, Gushing, and Pawhuska fields, all of which were large producers and were all practically exhausted within less than five years, in which the bulk was taken out within the first three years. CLASS F— NATURAL GAS GASOLINE PLANTS. Compression plants may be divided into compressors, engines, boilers, auxiliary equipment, cooling equipment, gathering and dis- tributing lines, blending tiinks, buildings, and electrical equipment. For absorption plants, separate items of absorbers, stills, con- densors, cooling equipment, auxiliary equipment, boilers, engines, electrical equipment, tanks, and loading racks may be considered. On the whole the average life of these i^lants is not over five or six years. The Fuel Administration made a survey of cost of natural gas gasoline plants. Over 800 questionnaires were sent out and of these about 400 were considered. Out of 175 plants tabulated nearly all are now plants or less than two years old, and of those operating at a loss almost all Avere over four years old. The returns of some 200 other plants were considered and are older plants, and were either not oper- ating or were so defective in their detail as not to be usable for com- parative purposes. In consideration of these data and other data at hand, it is recom- mended that: The original cost be placed on a 20 per cent salvajie. and the remain- ing 80 per cent be depreciated in four years at 35, 20, 15, and 10 per cent in the respective 3'ears. SUMMARY. RcTor- cnce. Page. 1 S7 2 57 3 57 4 68 S 58 6 58 7 58 8 58 9 69 Drilling cquipmont. Wolls. Dchydrators: Eloctric Pipe and tanks Tanks' Steel 5000-55000 bbl 2500-alK);l Oalvttiiizod-iron 500-2500. . l.css Hum 'lOO Wood For movable tanks: Oalvanlzed-iron 500-2500.. Loss thon 500 For water tanks: 500-2600 Less than 500 Tools Transportation equipment.... Water plants Electric equipment Machine shops. ., 16} 8 12i 5 20 3 33 3 33 1(1 10 10 10 7 W MANUAL FOR THE OIL AND GAS INDUSTRY. 65 Summary — Continued. Class No. Refer- ence. Useful life. Annual deprecia- tion. Page. 59 69 62 63 Buildings: Small wood Frame structure Corrugated-iron siding Concrete Brick Steel Pipe lines: Mains over 6 inches diameter Mains under 6 inches diameter Gathering lines Less 10 per cent salvage. Pump stations .• Tanicars Refineries: Class 1.— Located at point assuring a long supply ol crude oil; or weil-construoted plants. Class 2.— Located at points assuring supply of crude oil for several years. Class 3. — Skimming plants and small refineries of poor construction, or located at points where supply of crude oil is not assured for a long period of time. Sales or marketing equipment: Tankers Barges Filhng stations — Class A.— Ordinary wood or corrugated steel constniction. Class B. — Brick and concrete or extraordinary construction. Distributing stations Tank wagons- Motor Horse Steel barrels Track and switches Natural gas (utility companies): Drillmg equipment. CSee A-1.) Wells. (SeeA-2.) Gas pijie Imes— Gathering lines City lines Compressor stations Gathering stations Field stations Meters and regulators.. Considered as a whole plant Natural gas gasoline: Plant— Compression, with 20 per cent salvage value. Absorption plants, with 20 per cent salvage , Years. 10 15 6 25 25 25 20 16 10 10 20 20 10 6 Per cent: • 10 63 161 4 4 10 S 6 10 16J S 20 20 10 10 25 161 14J 12i 81 10 10 "f 16i 29 20 20 35-20-15-10 35-20-15-10 111069°— 19- PART III. ESTIMATION OF RECOVERABLE UNDERGROUND RESERVES OF OIL. PREFACE. There has been a sincere effort on the part of many petroleum engineers and technologists during the past few years to devise a rational system for estimating underground reserves of oil. Much valuable work along this line has been done by various engineers and results have been given out from time to time in the publications of the technical societies and Government bureaus. All sorts of methods and systems have been devised and most of them have merit, but the great difficulty has been to find one capable of general application. Since the enactment of the income and war revenue tax laws pro- ducers have become much interested in this work, as they, as well as the technologists engaged in it, realize that the only channel through which might come equalization of the tax burden on them is in the proper valuation (when permissible) of oil properties, careful esti- mates of the underground reserves, and then the use of these two factors in the computation of proper depletion allowances. During the autumn of the year 1918, the Internal Revenue Bureau of the Treasury Department, with the active cooperation of operators in the various districts, undertook the collection and tabulation of production data from all the fields in the United States for the pur- pose of making an intensive study of depletion. Records of pro- duction of thousands of properties were collected and tabulated. These were carefully gone over and studied by the most competent and experienced men in the country and the average future produc- tion curves and tables reproduced on succeeding pages of this man- ual are the result of their work. This study has confirmed the belief heretofore held that it is pos- sible to make estimates of recoverable underground reserves of oil wilhin reasonably narrow limits. It has shown that in the making of such estimates it is simplest and safest to use some variation oi production curve methods, because by the use of the productive his- tory of a well or property as a basis for a prediction of its future, esti- mation is confined to the future and the personal equation thus re- duced to a minimum. Production curves and the methods for using them in making esti- mates of underground reserves are very fully described in section A following. It may not be out of place here, however, to state briefly that a production curve is a graphic representation of the decline in 66 MANUAL FOK THE OIL AND GAS INDUSTBY. 67 production of a well or group of wells, and that the problem pre- sented to the estimator is the extrapolation or extension of the curve from the period of last recorded production to the economic limit for the property. A method devised for use in the older fields uses an average de- cline curve for this purpose, because a careful comparison of pro- duction records shows that while the rate of decline in produc- tion varies widely over the country as a whole, when the produc- tion records from smaller units such as pools are tabulated, the de- cline rates of individual wells or properties show a striking simi- larity, although there may be wide variations in gross production figures. In view of this fact, the data collected are grouped accord- ing to pools, and a curve plotted to show the average decline in pro- duction per well for the pool. This curve, or such portion of it as ia necessary, is reproduced in the extrapolation of the decline curve for any particular property within the district, but it must be used with caution because this average decline curve is only an average, and the probabilities are that each group of wells within the dis- trict is either above or below the average. However, with care and the use of judgment, the decline curves of any particular property may be extended in this manner and the results made to show very conservatively and within reasonable limits just what the property may be expected to produce in the future. To make the average decline curve the graphs from the production records for all the tracts in the district are assembled and assorted according to the amount of production in the last year shown and arranged in ascending order. The average interval of time required for the decline between certain arbitrarily fixed points, such as from 100 barrels to 50 barrels, or 1,000 barrels to 500 barrels, is found by ascertaining the numerical average of the time interval required for such decline on each of the properties in the district. The average declines so obtained are plotted and the resultant curve represents a true numerical average decline for every well in the district. This curve is simply an average of averages in decline and deals with known factors only.' Its greatest fault seems to lie in the fact that in the computation of averages, only the records of those wells which are exhausted, or very nearly so, can be used in the construction of the lower end of the curve, and usually the best wells are at the same time producing at a rate which may be considerably above the economic limit of the field. Consequently, the tendency of the lower end of the curve is to show that the underground reserves are somewhat less than they will actually prove to be. The advantage in the use of this method lies in the fact that all production records, no matter how erratic they may be, are used in its construction, without any smoothing out processes. A further advantage is that the personal equation as a factor in its construction is entirely eliminated. This is only one of many methods devised for making an average decline curve, and in turn the average decline curve is only one way of estimating reserves by production curve methods. For the convenience of those not accustomed to reading values from curves, tables have been prepared showing the average future 68 MANUAL, FOR THE OIL AND GAS INDUSTRY. production which may be expected from a well in most of the dis- tricts in the country if the production for the taxable year is known. Curves and tables are the same thing in different form. One thing, however, must be borne in mind. These curves a,nd tables represent average conditions only in the field or pool to which they apply. Everyone knows that an average well or property is seldom encountered, so in the application of curves or tables to a specific property due allowance must be made. A striking feature observed in connection with the study of these curves is that many decline curves of individual wells or properties which are anywhere near symmetrical, seem to assume approximately the shape of an hyperbola. Much interesting work has been done in the investigation of this feature with a view to the extrapolation of decline curves mathematically, because if a true decline curve is hyperbolic in form, when plotted on logarithmic coordinate paper it becomes a straight line, with the unlaiown factor in its equation, which is the slope of the line, definitely fixed in the earlier periods of production. This method of extrapolation of decline curves is worthy of consideration, but until better understood it must be used with extreme caution. As an essential element in calculating depletion allowances in the estimation of underground reserves, the rather full discussion of the methods found best for making these estimates by investigators work- ing with the department is given in this manual, for no single method or formula which may be generally applied has been found. The statement has been made many times in these pages, and can not be too strongly emphasized, that the curves and tables presented herewith represent only average conditions. In many cases they may be used safely by the operator of a single property. Where, however, holdings in any field or district are in any way extensive, it will, in most cases, be necessary for the op- erator to make special estimates, using any or all of the methods dis- cussed in this manual", or it may even be found necessary to devise new combinations to fit the peculiarities of a particular tract. - In any event, care, skill, and judgment must be exercised to the ut- most, and it is believed that the effort expended in this work on the part of the oil producer will be repaid many fold. Not only from a tax standpoint will this benefit come. A full Imowledge of conditions such as will be brought out by a study of this problem will put the oil-producing business generally on the much firmer and safer foun- dation to which it is rightfully entitled. Section A. METHODS OF ESTIMATING RECOVERABLE OIL RESERVES. Estimation of recoverable oil is possible. — The estimation of the fu- ture production of oil wells or of the recoverable oil underlying a property in the past has been considered an almost unsolvable prob- lem, but scientific progress has disclosed reasonably accurate solu- tions, especially where sufficient dependable data are brought to- gether and arranged in an orderly manner, for then it becomes evi- dent that there is "a system to things" and that "freaks" are com- lOOOO »^ 9000 § 6OO0^ k WOOi J^ 6000 ^ 5000 C^ 40C?0 1 % 2000 I ^ WOO: /W6 /90r /S08 111069°— 19. (To face page 6U.) /S09 /3/0 /SJJ /9/2 /9/3 fSJ4 /S/5 /9J6 FIG. ).— PRODUCTION DECLINE CURVE FOR A PROPERTY IN OKLAHOMA. /9/7 /9/8 /S/9 MANUAL, FOE THE GIL AND GAS INDUSTRY. 69 paratively few. The recovery of oil is controlled by scientific laws, and where enough facts are known these laws make themselves manifest. During the past ten years many petroleum engineers have been working on the problem of estimating the future production of oil wells, and much progress has been made. In fact, when enough facts are available, surprisingly close estimates are usually possible, and in the future, as more and more data are compiled and analyzed, it will be possible to make much closer estimates. ~ Plotting production curves. — The production-curve method is one of the sinaplest and, when sufficient data are available, is, perhaps, the most accurate of all the methods for estimating the future production of oil wells. A production curve is a graphical record of the pro- duction of a well or group of wells, plotted on coordinate paper (fig. 1). It is desirable to have the production records of individual wells, but as these are kept in but a few fields, it is usually necessary to use the production record of the group of wells on a property. To provide a basis of comparison between wells, the yearly pro- duction of a property is divided by the number of wells producing each year, thus giving the average production per well for each year. The record of an Oklahoma property that has been prepared for plotting in a production curve is given herewith. year. Produc- tion. Wells pro- ducing. AA'crage per well. Year. Produc- tion. Wells pro- ducing. Average per well. 1906 Barrels. 46,860 31,717 15,003 11,031 7,047 4,622 6 6 t 6 6 Barrels. 9,372 5,286 2,501 1,838 1,174 764 1912 Barrels. 2,462 1,641 1,061 578 218 6 6 6 6 Bands. 410 1907 1913 274 1908 1914 177 1909 1915 96 1910 1916 -. 36 1911 On a sheet of coordinate paper, as in figure 1, the spaces between the light horizontal lines represent 100 barrels each and those be- tween the heavy lines which are ten times as far apart, represent IjOOO barrels each. The heavy vertical lines represent years; thus, space between the horizontal lines represents production and between the vertical lines time. For convenience, these lines are labeled on the margins as in figures 1 and 2. Taking the record given, the first year is 1906, during which year the average production for each well was 9,372 barrels. A point is then made on the vertical line representing the year 1906 and a dis- tance representing 9,872 barrels above the bottom, which is 9 heavy lines and 3| light lines. Similarly a point is made on the line representing 1907, 5 heavy lines and 3 light lines above the bottom. And on the line representing 1908, 2 heavy and 5 light lines above the bottom show the production of 2,501 barrels for that year. The pro- duction for the rest of the years are then plotted and the points con- nected up by lines to make the curve as in figure 1. It will be ob- served at once that the plotted record makes a fairly regular and symmetrical curve. , • j. Manifestly, there is a certain relation between the production o± the successive years that is not easily seen in the column of figures 70 MANUAL rOK THB OIL. AND GAS INDTJSTBY. from which this curve was derived. Plotting production records in this manner has many advantages and permits the mind to grasp readily facts that otherwise would be obscured in a mass of figures. Estimating future production by production curves. — ^Many thousand production or decline curves have been plotted by petroleum raigi- neers in the manner shown, and from this wide expierienGe it has developed that the relationships between the production of various years are such that the curves are usually notably symmetrical. Furthermore, it has been found that such curves can be extended beyond the actual pexiod of production by continuing the curves in accordance with their symmetry and that such projections, if skill- fully made, provide fairly trustworthy estimates of the future pro- duction of the well. The estimation of the future production by the curves of past pro- duction is illustrated in figure 2. The actual record extends six years — from 1911 to 1916 — and is shown by the small circles con- nected by the heavy lines. The dotted line shows the symmetry of this portion of the curve and beyond the year 1916, shows the ex- tension from which estimates of future prod'uctions are made up to the year 1925. For 1917 the estimated production is 1,700 barrels, for 1918, 1,500 barrels, and for 1919, 1,300 barrels. By adding these estimates of the future years, an estimate of the total future pro- duction is obtained. It is to be noted that production curves like figures 1 and 2 deal with actual facts and conditions on particular properties. Only the oil gauged is considered, hence all the various practical facts of field conditions are automatically taken into account. The extension of the curve estimating future production is based on the past behavior of the wells on the particular property which established the sym- metry of the curve. This symmetry is not accidental but is the re- sult of underlying natural laws governing the expulsion of the oil from the producing strata. In figure 1 it is evident that the produc- tion of the last six years could have been closely estimated from the production curve of the first five years. This method and others based on it have proved satisfactory in the appraisal of many large properties. Obviously, manner of operation, accidents, and other factors will influence the future production just as they have the past production but experience has shown that ordinarily these are not likely to. cause wide deviation from estimates that have been carefully made. Examination of the individual production records will show whether the probability of such occurrences will make estimates unsafe. The appraisal-curve method. — The production-curve method, just discussed, necessitates a record of at least four years before any re- liable estimate of the future production is possible, and usually such estimates can not be made satisfactorily until the wells have produced for several years. In the most satisfactory methods for properties that have not produced this long, the future production of weEs is estimated by comparison with the behavior of other wells in the same or similar districts that have produced long enough to establish trust- worthy production curves. Usually the methods of estimation are based on the average behavior of the older wells because the be- havior of the new wells will approximate this average. I >s> 10000 9000 8000 7000 6000 5000 I 4000 3000 ZOOO /OOO /a// /S/2 /S/S /0/4- /0/S /m ISl? /m I9I9 /S20 /Se/ /^^ /S23 /S24 132^ FIG. 2.— PRODUCTION DECLINE CURVE. SHOWING THE EXTENDED CURVE OF PROBABLE FUTURE PRODUCTION. 111069°— 19. (To face page 70.) MANUAL FOB THE OIL AND GAS INDUSTRY. 71 The appraisal curve is built up from records of individual wells or groups of wells within a certain district and is applied to wells within the same district that have not produced long enough to per- mit estimates of future production by extension of the production curve. It may be necessary at times to apply appraisal curves of one district to other districts for which there are not enough reliable records to make appraisal curves, and in such cases care must be taken to select curves from districts most similar. The appraisal curve, illustrated by figure 3, is based on the re- lation that exists between the production of wells for their first year, and the quantities of oil they will produce ultimately. This par- ticular figure was drawn from the production records of 209 proper- ties in an Oklahoma field. As the average property in that field contains 10 producing wells, the figure may be said to represent about 2,000 wells. The records of each property were taken and each year's average daily production per well was computed and curves plotted from them. Only records where practically the full production had been obtained or where the future could be estimated with confidence were used. From these curves the future production of each property was estimated as explained above (Figs. 1 and 2). The future production of each property was added to past produc- tion to determine the ultimate production for each property. The next step was to plot for each property the average production per well during the first year or second year against the ultimate production of the well. Each dot, therefore, on figure 3, shows the average production per well the first year on a property and the estimated average ultimate production per well. These dots, which represent the ultimate production of more than 200 properties, on which the wells were of many different sizes the first year, arrange themselves in a strikingly orderly manner, leaving no doubt of the existence of a definite relation between the first year's production of a well and its ultimate production. There is a consid- erable variation in ultimate production, however, both for wells of different and for wells of the same initial output. These dots define the positions of the three curves drawn in to show the average and the range in ultimate production that may be ex- pected from wells of different output in this field. It shows that two wells in this field with the same production the first year may pro- duce different totals, yet the amount that a well of a certain output will produce will not exceed a certain maximum nor will it be less than a certain minimum. The producer, therefore, can be reasonably sure that he will not get more than a certain maximum amount of oil nor less than a certain minimum amount and is really more likely to obtain finally the amount shown by the average curve than either the maximum or minimum. Figure 3 has been worked out on the law of averages similar to the fimdamental laws underlying life insurance. Actuaries know, not by theory but from the analysis of great masses of data, the prob- able life of a man of any specified age, though an individual man might die the next day, or, on the other hand, might live to be a very old age. If 10,000 men are considered, however, it is possible to predict within extremely narrow limits the age at which the average man of the group will die, and also how many men of the 10,000 will die at any specified age. 72 MANUAL FOR THE OIL AND GAS INDUSTRY. The method illustrated in figure 3 makes use of the first year's production, but the most recent year's production may be used with equal assurance, and the total production, beginning with the produc- tion of the well for the past year, can be worked out in the same man- ner. This fact is based on a conclusion for which there seems to be abundant statistical proof. This is as follows : // troo wells under similar conditions produce equal amou/nts dur- ing any given year the amounts they will produce thereafter, on the average, will he approximately equal, regardless of their relative ages. That is, if two groups of wells in the same pool have averaged, say, 5 barrels per day during the past year, they will on the average produce the same amount of oil in the future, even though the wells of one group may be only 2 years old, whereas the wells of the other group may be 5 years old. The writers were at first skeptical, but finally were forced to this conclusion because of the preponderance of evidence disclosed by the records of many thousands of wells in many different fields. It must be carefully noted that the above statement is made for thb average and applies to only one pool. The future production of any two wells may differ widely but for two large groups of wells in the same district whose current production averages the same, the statement holds true, hence if nothing is known of the past histories of two wells from which their futures may be estimated, their chances of production will be equal even though one well is much older and according to the popular idea has a more settled production. This law of equal expectations makes possible the derivation of appraisal curves like figure 3 by other methods than the one illus- trated. The curves for many of the fields were checked by two or more methods of derivation. To estimate future production from this curve it is necessary to know the first or the most recent year's production and the number of Avells producing during that year. From this the average pro- duction per well is computed. Readings are then made at the inter- sections of the vertical lines, representing the average yearly pro- duction per well with the curves, and the horizontal lines on which tliese intersections lie are then followed to the right or left. This gi\es the maximum, average, and minimum ultimate production that may be expected per well. For examjDle, if the wells average 30 bar- rels daily during any year, the 30-barrel line is followed vertically to the intersection with the minimum curve at 16,200, the average at 28,000, and the maximum at 40,500 barrels. Thus, the average 30- barrel well will produce not more than 40,500 barrels, at least 16,200 barrels, but more likely it will produce approximately 28,000 barrels. To compute the future production, the year's production — 10,950 bar- rels — must be subtracted from these estimates. This gives the maxi- mum, average, and minimum future estimates as 29,550, 17,050, and 5,250 barrels, respectively. In some cases the average future production curves shown in the succeeding pages were determined in this way — that is, the past year's production was subtracted from the estimated average ultimate pro- duction, as shown by the average ultimate production curves. These estimates of average future production were plotted and a curve drawn through the plotted points. In other cases the future-produc- i 1 Ml 1 [ 1 iij iiM ■ uj-^t-|4t^i 1 ! 1 1 i N 1 H iTiTiMri rTMTi"mTrHT[T^^ iV]\ ' 1 J m '"x* ^^ooo .[^i 1 1 1 1 1 1 1 1 1 1 1 1 1 [ i 1 1 ,1 J , |. j. . \\ ■ ■ -\ Hm iiii' ii'iijl l| 1 1 II 1 1 i IMiii >i'iir i mili^^^^ |;|X.:|,;H|:;:::|:i;|::i|:;::;|||# ^£55^^£?:|x+i:ffi+xxxxxxx:|xxxxx±xxxxxxxx:4±:^x:i+x|:|± ^ HWMWB WHi '^m4 'MMffM II i 1 |Hi:iiiil;;!!i!|i;lilinH;ii:l;iiiil--i 7^^^c^:::^::::::±::n::::::::;:::::::::::::|:::::T----------g-|-----.--------^ ±±±_± ,^ .,_'___: -; i:X - X X-' -- ' i :4:xXX b XxtEq==EExtEExxxt:Exxxxxxx4xxxx""=-"-"=i;-^ = "" C^. x:i4:Sx:#X±xxxxxxxxxxx4xxxxxx:xxx^S:=:::::::::::::::::=:''^''"^ <5i7<5'^:±±:±xxxxxxxxxXxxT±xx:jxxxxx:xxiri:::::^::;-:::::::::::::::;;^f:::::::::::^ >j X"": ;---- ;-;— x"X":":""";"xx"±x"^'"± ±x :~ XX"X xt x"";='±""± i X"X"j ^ 4: + X ,^-.._.; x^x^±±-;^±±:xxxxxX::::;:;:::+-;::t:-:.:+:^:::_:;:ixxxt ^ ^a5C7C?:ixxxxxxxxxxx±xx:Sxxxx?!::?±±:4:x::;:xf4±irf:±xxx:x:±^ ? 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'cvjj':'- / '•' ^ '< a ^ j^ ' \ f , ^' . ],-'■■ 1 " ■ ■■ ■ " "" ■-■■,*>.'• ■ ^^ : '■ i-px e: +--- - ----- ^ -'xx -t 4^x + x -- _ _ _ " " _:± "^ ± : xt __ _ i - -I- ' f * / .^ " ■ -' * it *z . _ •^ » _ ■,'!_!: X X - - _- -i -- I ■ -iX-f-- ti •\ ' '' 'T^i^'' ■ ■' ^^ M- -H H- -1- -t- -1- ■■■" J T« imf^x >• ,' ' ■ / Hi i ' r " - r^- T ■• y < ' - /<:?'7^'(? "*"■/■"» -{•&>> .r' 1 i 1 ' ■" — 'i9:n?~ " "Br?*. "^aT 3" ■ 1 ! ; ^ ! ^ " " . ~" ^ISl.' *.,'--• ^ 1 ^_f. __.4..4-j4-X-f|-M--tr-- i f-i H-1X-1 i- ^ Ti t^^""^'^^^^^ ^-^ ^ ^XH-x-^xhr^J L_,+hXJ ^^_„_^4XX— U- /^ WfW 1 14-rt+T+i 1 II 1 M 1 1 f II ' 1 1 1 1 l-H-t-f-M-^ 1 1 1 ; 1 ! I M 1 1 1,,L., .,.* LiLUIU 'HIOO SOOO /2000 /6000 20000 240ao Z&OCK) JZOOO 36000 -40000 4400O — Product/or? Per i//e// f/r000 52,000 30,400 74,000 41,000 10,000 7,100 32,000 20,100 54,000 31,400 76,000 41,900 12,000 8,400 34,000 21,150 56,000 32,300 78,000 42,900 14,000 9,700 36,000 22,200 58,000 33,300 80,000 43,800 16,000 10,900 38,000 23,250 60,000 34,300 18,000 11,100 40,000 24,300 62,000 35,300 20,000 13,300 42,000 26,350 64,000 36,200 FUTURE PRODUCTION CURVES FOR THE CALIFORNIA OIL FIELDS. The California oil fields may be roughly divided into two provinces, the first province occupying both sides of the San Joaquin Valley and commonly known as the Valley fields, and the second occupying a large coastal area and commonly known as the Coastal fields. The Valley fields, with one exception, lie on the west side of the San Joaquin Valley and produce the bulk of their oil from the porous Tertiary sandstones, which have been folded into arches and troughs — anticlines and synclines. Although the prevailing type of structure controlling the oil accumulation is relatively sharply folded anti- clines, considerable oil has been produced from monoclines and syn- clines. The conditions in the Coastal fields are similar in many re- spects to those of the Valley fields, although a much greater variety of structure is present. The bulk of the oil produced in California comes from formations of Tertiary age, the proportion coming from the older underlying Cretaceous formations being practically negligible. The principal rocks comprising the oil-bearing series are interbedded sandstones and shales, the oil probably originating in the organic diatomaceous shales and later being accumulated in pools in the overlying or under- lying porous sandstones. Throughout a long stratigraphic range of these Tertiary rocks, the oil-bearing sandstones occur, those in one field at one horizon, whereas those in a near-by field may be encoun- tered at an entirely different horizon. The California fields are usually large and the factors affecting production are rather variable — sometimes even in the same area. For this reason, in preparing curves showing the average future pro- duction of wells of varying size, it was necessary to divide some of the larger fields into individual productive units, each unit includ- ing all the wells or properties producing under similar conditions. Furthermore, many of the California fields are underlain by more than one productive oil zone, and it was necessary to prepare curves showing the average future production of wells that produced from each of these zones. In the following presentation of the curves, the area for which each curve is designed is described, and the zone 112 MANUAL, FOR THE OIL AND GAS INDUSTRY. from which the wells produce, that serve as a basis for the curve, is stated. Occasionally zone A, in one part of a large field like the Midway field may be geologically equivalent to zone B in another part of the field. No attempt has been made to corelate these zones from one area to another, as none of the curves applies to wells producing from a single zone in different areas. Because of the lack of data, average future production curves could not be drawn for all producing areas. Only the larger areas are covered. Estimates of the average future production of wells in these areas made by using the curves should be made with caution and with knowledge of the fact that the curves represent average conditions, although all the curves presented have been carefully checked by selecting properties at random and making estimates of their future production by the use of the curves. It should be noted that practically all the curves are based on the records of individual wells, only a few having been prepared from the tract production records. For this reason, estimates of the fu- ture production of tracts can best be made by using the former curve for estimating the future production of individual wells, and then totaling the estimates of the separate wells. In case a curve has been prepared from records of tract production, an estimate of the future production of any tract in the area may be obtained by determining the average production per well during the last year, determining the future of a well of this size from the curve and then multiplying this estimate by the number of wells. It is true that the future production of an average well on a tract may be made from a curve based on the production records of individual wells. Tiie practice is not recommended, however, because of the greater possibility of error. Much closer estimates may be made if the curves based on the individual wells are used only for making estimates of the average future production of individual wells. The following examples of procedure in making estimates under certain conditions may be of use: Case I. — In case a producer desires to estimate the future produc- tion of a tract completely drilled on which the production is gradually declining, it is unnecessary to use the average future production curve for the district in which the property is situated. Very likely a much closer estimate can be made by plotting the annual production of the property and by projecting its curve as shown in figure 2 of the paper on "Methods of estimating recoverable underground re- serves " in another part of this manual. Case II,— If a property is so nearly drilled up that drainage has materially affected the probable initial production of the undrilled wells on the proved acreage, a curve showing the average annual pro- duction per well may be plotted and projected to the estimated economic minimum. The production for any future year may be estimated by multiplying the I'eading on the projected curve for that year by the number of wells to be producing. In this manner the undrilled wells are considered. This method can not be used unless drainage, within all likelihood, has affected the oil reserves under the undrilled territory. MANUAL FOR THE OIL AND GAS INDUSTRY. 113 Case in.— A variation of the above method is to estimate the future production of the drilled wells as in Case I or II and determine the ultimate production per acre for the drilled part of the tract and to apply these determined values per acre, with the proper modifications, to the undriUed portion of the tract that is practically certain to produce oil. Case IV. — Still another method is as follows: Proceed as in the first part of Case III. Then estimate the first year's production of the undriUed wells, preferably by using as a basis' of estimate the first yea-r's production of the drilled wells. Determine the future of wells of this size by using the average future production curve. The future production of the proved undriUed land will be the sum of the esti- mated first year's production and the estimated production thereafter. THE MIDWAY-SUNSET FIELD. The Midway- Sunset field is so large and producing oil under such diverse conditions that it has been necessary for the present work to divide it into several separate areas, each area containing the wells that produce oil under practically equivalent conditions. In some parts of the field three zones are productive. One very marked feature in the underground geologic conditions is the wedging out of the older or basal beds of the Etchegoin formation, along the plane of unconformity between the base of the McKittrick formation and the top of the Maricopa (Monterey) shale. This wedging out causes a decrease in thickness of the productive zone, or the entire elimination of the lower zone toward the outcrop to the west. The wells southwest of the line where these zones combine produce under different conditions from those northeast of that line. For that reason, the area west, southAvest, and south of the Buena Vista Hills have been divided into three separate areas, and an aver- age future production curve prepared for each area. There are four areas considered therefore in the Midway-Sunset field. 1. The Fellows Area. 2. The Twenty-five Hill Area. 3. The Maricopa Flat Area. i. The Buena Vista Hills Area. It is true that these areas do not include all the wells in the Mid- way-Sunset field, but the scattered wells outside these areas do not provide sufficiently trustworthy and plentiful records upon which to base curves. FELLOWS AREA, MIDWAT FIELD, CALIFORNIA. This area includes most of the wells producing from the thick sand caused by the coalescence of the two zones found to the east. The area may be roughly defined as including all those wells southwest of a line drawn as follows : Beginning at the northwest corner of section 26, township 3 south, range 22 east, proceed southeast to the southeast corner of the same section, thence to a point | mile north of the southeast corner section 36, township 31 south, range 22 east, and thence southeast to a point i mile north of the center of the south line of section 5, township 32 south, range 23 east, where the area terminates. The curve was prepared from the individual records oi />J'J.st of the wells in this area. 111069°— 19 8 114 MANTJMi FOE THE OIL AND GAS IWD0STBT. Estimated future prod'uction table, Feliows area of the Midway field. Avsrage Eslamated Avaraee production Estimated Avetaga producnon Bstimated Average Estimated production average average average production average per well luture -par well future P6r well ftiture per well future during tax- production during tax- production during tax- production during tax- production able year. per well. able year. per well. able year. per well. able year. per well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 1,080 20,000 66,000 89,000 103,500 76,000 179,500 2,000 3,000 21,000 58,500 40,000 106,008 78,000 183,000 3,000 6,000 22,000 61,000 42,000 111,000 80,000 186,500 4,000 9,000 23,000 63,500 44,000 115,500 85,000 195,060 B,flOO 12,000 24,000 66,000 46,000 120,000 BO.OOO ^seo 6,000 16,000 25,000 68,500 48,000 124,600 96,000 .212,000 7,000 18,000 26,000 71,000 60,000 129,000 100,000 220,500 8,000 41,000 27,000 73,500 62,000 133,500 105,000 429,000 9,000 34,000 28,000 76,000 54,000 137,500 110,000 237,500 10,000 27,000 29,000 78,600 66,000 141,500 115,000 246,000 11,000 30,000 30,000 81,000 68,000 145,500 120,000 254,000 12,000 33,000 81,000 83,500 60,000 149,500 126,000 262,000 13,000 36,000 32,000 86,000 62,000 153,500 130,000 270,000 14,000 39,000 83,000 88,600 64,000 167,500 135,000 277,500 16,000 42,000 34,000 91,000 66,000 161,600 140,000 285,000 16,000 46,000 86,000 93,600 68,000 185,500 146 000 292,600 17,000 48,000 36,000 96,000 70,000 169,000 160,000 ; 300,000 18,000 61,000 37,000 98,500 72,000 172,500 155,000 307,500 19,000 63,600 38,000 101,000 74,000 176,000 1«0,000 815,000 TWENTY-FIVE HILL AREA, MIDWAY FIELD, CALIFOKNIA. This area lies southeast of the Fellows Area and includEs all wells lying southwest of a line extending southeastward from a point i mile south of the center of section 5, township 32 south, range 23 east, to the center of the south line of section 15, township 32 south, range 23 east, thence to the center of the east line of section 23, township 32 south, range 23 east, and thence to tlie center of the south line of sec- tion 30, township 32 south, range 24 east. AH wells in section 15, township 31 south, range 22 east, and those producing from the first zone only in sections 14 and 23, township 31 south, range 22 east, are also included in this area, and estimates of the future production of these wells may be made by using the same curve. Estimated future production table, Twenty-five Hill area. Average production Estimated Average production Estimated Average Estimated Average Estimated average average production average production average per well future per well future per well future per well during tax- production during tax production during tax- production during tax- production able year. per well. able year. per well. able year. per well. able year. per well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 1,000 6,000 31,700 13,000 62,100 26,000 91,100 1,250 2,800 5,500 34,300 13, 500 63, 400 27,000 93,100 1,500 6,400 6,000 36,800 14,000 64,700 28,000 95,100 1,750 7,900 6,500 39,200 14,500 66,000 20,000 97,100 2,000 10,300 7,000 41,500 16,000 67,300 30,000 99,100 2,260 12,600 7,600 43,700 16,000 69,800 81,000 101,100 2,600 14,700 8,000 45,800 17,000 72,200 32,000 103,100 2,760 16,700 8,500 47,700 18,000 74,500 33,000 105,100 3,000 18,600 9,000 49,600 19,000 76,700 34,000 107, 100 3, 2.50 20,400 9,500 51,200 20,000 78,800 35,000 109,100 3, .'iOO 22,200 10,000 62,900 21,000 80,900 86,000 111,100 3,7.50 23,900 10, 500 64,600 22,000 83,000 37,000 113,100 4,000 26,600 11,000 56,200 23,000 85,100 38,000 115,100 4,250 27, 200 U,600 67,700 24,000 87,100 39,000 117,100 4, 500 28, 800 12,000 69,200 26,000 89,100 40, 000 119, 000 4,750 30,300 12,600 60,700 MANUAL FOB THE OIL AND GAS INDUSTRY. MARICOPA FLAT AREA. 115 The curve for this area was .prepared from the records of indi- vidual wells that produce from the first zone only in the area known as the Maricopa Flat in the Sunset field. The curve should be used for estimating the future production of individual wells at present producing from this zone and for making similar estimates of other wells drilled to this zone. Future production table for a portion of the Sunset oil field, Califoi-nia, Maricopa Flat areas. Average Estimated Average production Estimated Average Estimated Average production Estimated production average average production average per -well future per well luture per wen future during tax- production doling tax- production during tax- production during tax- production per well. able year. per well. able year. per well. able year. per well. Barrels. Barrels. -BamU. Barrels. Barrels. Barrels. Barrels. Barrels. 1,000 11,000 61,000 21,000 78,500 31,000 101,200 7,800 12,000 54,100 22,000 80,900 32,000 103,400 3,000 14,500 13,000 67,100 23,000 83,200 33,000 105,600 4,000 20,500 14,000 60,000 24,000 86,500 34,000 107,800 6,000 26,000 16,000 62,900 26,000 87,800 35,000 110,000 6,000 31,000 16,000 65,700 26,000 90,100 36,000 112, 100 7,000 35,600 17,000 68,400 27,000 92,400 37,000 114,200 8,000 40,000 18,000 71,100 28,000 94,600 38,000 116,200 9,000 44,000 19,000 73,700 29,000 96,800 39,000 118,200 10,000 47,700 20,000 76,200 •30,000 09,000 40,000 120,200 BUENA VISTA HII/LS AREA, MIDWAY FIELD, CALIF. This curve was prepared from the records of individual wells drilled on practically drilled-up tracts in the Buena Vista Hills. The only records omitted in making the curve were the records of such wells as those belonging to the Honolulu Consolidated Oil Co. in section 6, township 32 south, range 24 east, which have large drainage areas with no, or v^y little interference, thus causing the wells to decline slowly. Practically all the wells in this area were treated as if they were producing from one thick zone, for in nearly all parts of the area where a division can be made, the wells now produce without water from both. Estimated future production table — Buena Tista Sills. Average Estimated Average Estimated Average Estimated Average production Estimated ^roduotian average production average production average average per well future per well future per well luture per well future during tax- production during tax- production during tax- production during tax- production able year. per well. able year. per well. able year. per weU. able year. per well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 2,000 44,000 123,000 130,000 229,000 230,000 324,000 4,000 9,000 48,000 130,000 136,000 234,000 236,000 329,000 6,000 17,000 62,000 137,000 140,000 239,000 240,000 334,000 8,000 24,000 56,000 144,000 145,000 243,000 245,000 338,000 10,000 32,000 60,000 150,000 160,000 248,000 250,000 343,000 12,000 39,000 64,000 166,000 155,000 263,000 255,000 348,000 14,000 45,000 68,000 161,000 160,009 258,000 260,000 363,000 16,000 62,000 72,000 168,000 166,000 265,000 285,000 367,000 18,000 58,000 76,000 171,000 170,000 287,000 270,000 362,000 20,000 66,000 80,000 176,000 176,000 272,000 275.000 367,000 22,000 71,000 84,000 181,000 180,000 277,000 280,000 372,000 24,000 76,000 88,000 185,000 185,000 282,000 286,000 377,000 26,000 82 000 92,000 189,000 190,000 286,000 290,000 381,000 28,000 87,000 96,000 1«4,000 195,000 291,000 296,000 386,000 30,000 93,000 100,000 198,000 200,000 296,000 300,000 391,000 32,000 98,000 106,000 203,000 205,000 300,000 306,000 396,000 34,000 102,000 110,000 208,000 210,000 305,000 310,000 401,000 36,000 106,000 115,000 214,000 216,000 310,000 315,000 406,000 38,000 ,111,000 120,000 218,000 220,000 314,000 320,000 410,000 40,000 115,000 125,000 224,000 225,000 319,000 116 MANUAL FOB THE OIL AND GAS INDUSTRY. m'kittrick field, kern county, calif. The McKittrick field has been very productive, but on account of complex structure, which causes the wells to produce different amounts at different rates, there is a considerable range in produc- tivity. The curve shown was prepared from the production records of many different tracts in this field. Estimates made by the use of this curve should show within a small percentage of error the amount that actually will be produced. Estimated future production tahle. McKittrick field. Average Estimated Average Estimated Average Estimated Average Estimated production average production average production average production average per well future per well future per well future per well future during tax- production during tax- production during tax- production during tax- production able year. per well. able year. per well. able year. per well. able year. per well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 1,000 8,000 69,000 20,000 144,000 38,000 213,000 1,500 6,000 8,600 73,000 21,000 148,000 40,000 219,000 2,000 12,000 9,000 77,000 22,000 152,000 42,000 226,000 2,600 17,000 9,500 81,000 23,000 167,000 44,000 232,000 3,000 22,000 10,000 85,000 24,000 161,000 46,000 239,000 3,600 27,000 11,000 92,000 25,000 165,000 48,000 246,000 4,000 32,000 12,000 99,000 26,000 169,000 60,000 252,000 4,500 37,000 13,000 106,000 27,000 173,000 ^•^ 268,000 6,000 42,000 14,000 112,000 28,000 177,000 64,000 265,000 6,600 47,000 15,000 118,000 29,000 181,000 ■ 56,000 271,000 6,000 52,000 16,000 124,000 30,000 184,000 68,000 277,000 6,500 56,000 17,000 129,000 32,000 192,000 60,000 283,000 7,000 61,000 18,000 134,000 34,000 199,000 7,500 65,000 19,000 139,000 36,000 206,000 CALIF. The Belridge field lies between the Lost Hills and McKittrick oil fields, on an anticline extending northwest-southeast. There are two distinct oil zones on this field, but most of the oil to date had come from the upper zone. In fact, so few wells have been drilled to the second zone that practically no production records were available for the preparation of a curve. The curve was prepared from the records of individual wells. Estimated future production table, Belridge field. Average Estimated Average Estimated Average Estimated Average Estimated production average production average production average production average per well future per well future per well future per well future during tax- production during tax- production during tax- production during tax- production able year. per well. able year. per well. able year. per well. able year. per well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 1,000 19,000 69,200 37,000 93,100 70,000 135,900 2,000 4,900 20,000 61,400 38,000 94,600 72,000 138,100 3,000 9,400 21,000 63,600 39,000 96,100 74,000 140,300 4,000 13,500 22,000 65,800 40,000 97,600 76,000 142,600 5,000 17,300 23,000 67,900 42,000 100,600 78,000 144,700 6,000 21,000 24,000 69,900 44,000 103,500 80,000 146,900 7,000 24,600 25,000 71,900 46,000 105,400 85,000 151,900 8,000 28,100 26,000 73,900 48,000 109,200 90,000 156,700 9,000 31,500 27,000 75,900 60,000 111,900 95,000 161,300 10,000 34,800 28,000 77,800 62,000 114,500 100,000 165,700 11,000 38,000 29,000 79,700 64,000 117,100 106,000 170,000 12,000 41,100 30,000 81,600 66,000 119,600 110,000 174,200 13,000 44,000 31,000 83,300 •68,000 122,100 115,000 178,400 14,000 46,800 32,000 8-5,000 60,000 124,500 120,000 182,500 15,000 49,500 33,000 88, 700 62,000 123,900 125,000 186,500 10,000 52,100 34,000 88,400 64,000 129,200 130,000 190,400 17,000 54,600 35,000 90,000 66,000 131,500 135,000 194,200 18,000 66,900 38,000 91,600 68,000 133,700 140,000 197,900 MANUAL, FOR THE OIL AND GAS INDUSTRY. LOST HILLS FIELD, KEEN COUNTY, CALIE. 117 This field IS located between the Coalinga and Midway oil fields on the west side of the San Joaquin Valley. The structure is that of an anticline that plunges southeastward. The greater part of the known producing area is underlain by two zones, the top of the first of which is encountered at depths ranging from 400 to 750 feet and the top of the second being encountered in the southern end of the field at depths ranging from 1,500 to 1,900 feet. In the southern end of the field, the interval between the zones appears to be greater than in the northwestern end of the field. A separate curve was prepared for those wells producing from the second zone, but it was found to be practically identical with that prepared for the whole field, so only the latter is given. This curve was prepared from the record of individual wells. Estimated future production table. Lost Hills field. Average Estimated Average Estimated Average Estimated Average production Estimated production average production average production average average per well i future per well . future per well future per well future during tax- production during tax- production during tax- production during tax- production able year. per weU. able year. per well. able year. per well. able year. per well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 1,000 16,000 45,800 31,000 79,200 62,000 117,900 2,000 4,000 17,000 48,200 32,000 81,200 54,000 121,500 3,000 8,000 18,000 50,600 33,000 83,200 56,000 125,000 4,000 11,600 19,000 63, 200 34,000 86,200 58,000 128,500 5,000 16,000 20,000 55,600 36,000 87,100 60,000 131,900 6,000 18,200 21,000 57,800 36,000 89,000 62,000 135,200 7,000 21,200 22,000 60, 100 37,000 90,900 64, 000 138, 400 8,000 24,200 23,000 62,400 38,000 92,700 66,000 141,600 9,000 27,000 24,000 64,600 39,000 94,500 68,000 144,800 10,000 29,800 25,000 66,800 40,000 96, 300 70,000 148, 000 11,000 32,600 26,000 69, 000 42,000 99,900 72,000 161,200 12, 000 35, 400 27,000 71,100 44,000 103, 600 74,000 154,400 13,000 38, 100 28,000 73,200 46,000 107,100 76,000 157, 600 14,000 40,700 29,000 75,200 48, 000 110,700 78,000 160,800 i5,ogo 43,300 30,000 77,200 50,000 114,300 80,000 164,000 \VEST SIDE COALINGA FIELD, FRESNO COUNTY, CALIF. This field is located on a monocline, the producing strata form one zone, ranging in thickness from 200 to 325 feet, approximately. The records indicate at least three sands in this zone. A fourth has been recognized in a part of the area. The curve shown is designed for all the wells in the West Side field, and was prepared from practically all the available trustworthy data that could be obtained on the output of individual wells. It should be remembered that this curve repre- sents the average future production of the wells of different sizes, and .estimates of future production made by using this curve may be slightly in error if the wells for which the estimates are being made are not average wells. 118 MASrUAIi FOE THE OIL AJSD GAS LNDUSIKY. Estimated future production table, West Side field , Coalinga A-roraM Estimated Average Xistimated Avmam production EstlmatBd, Average production Estimated production a-verago production average average average per well future per -well future perw«ll .future per well ituture during tax- production during tax- production during tax- production during tan- production able year. per well. able year. -per well. able year. pertrell. able year. per wen. Barrels. .Barrelt. Marrds. Bmreb. BarreU. BarreU. BmrOt. Barrelt. 2,000 17,000 75,600 44,000 180,500 9S,(X» an,soo 3,000^ 6,000 18,000 •80,000 46,000 186,000 100,000 285,000 4,000 11,500 19,000 84,«00 48,000 191,000 196,000 105,0)0 292,500 5,000 16,000 20,000 89,000 50,000 110,000 300,000 6,000 m,00D n,om 98,000 S2J00O 301,000 i 115,000 307,500 7,000 26,000 ai,ooo 107,000 54,000 205,600 120,000 315,000 8,000 31.000 36,080 115,500 56,000 210,000 125,000 322,500 8,000 -36,«I0 28,000 134,000 58,000 314,060 130,4»0 ^,000 10,000 41,000 30,000 132,000 60,000 218,000 135,000 337,000 11,000 i46,000: 82,000 140,000 66,000 227,600 140,000 344,000 12,000 61,000 34,000 147,500 70,000 236,^500 145,000 JS1,«X) 13,000 66,000' 36,000 155,000 75,000 246,600 150,000 358,000 14,000 61,000 38,000 162,000 80,000 254,000 155,000 365,000 15,000 66,000 40,000 168,500 85,000 262,000 160,000 372,000 16,000 71,000 42,000 174,500 80,000 270,000 EAST SIDE COALINGA FIELD, FRESNO COUNTY, CALIF. This field is located on an anticline which plunges to the south- eastward. Two different zones produce oil on the East Side. The oil from the first zone ranges in gravity from 24 to 28 Baume, a,nd that from the second zone from 22 to 24 Baume. The curve shown in the figure is made up from the individual production records of many ' East Side wells. It may be used for estimating the future produc- tion of normal individual wells. A separate curve was made for the wells in that portion of the field on sections 21, 22, 27, and 28, town- ship 19 south, range 15 east, which produces from both zones but the results were practically identical with those derived from the curve covering aU the wells of the East Side. Consequently, but one curve is given. Estimates made from it should be carefully examined and consideration given to tlie esti- mate of the future production of unusual wells, of which there are many in this area. Estimated future production table, East Side field GoaUnga Average production Estimated Averaee production Estimated Average production Estimated Average Estimated average average average production average per well future per well future per well future per well future during tax- production during tax- production during tax- production during tax- production able year. per well. able y«ar. per well. able year. per weU. able year. per well. Barrels. Barrels. Barrels. Sorrels. Barrels. Barrels. Barrels. 1,000 20,000 83,400 39,000 144,100 78,000 338,700 2,000 6,500 21,000 87,000 40,000 147,000 78,000 243,400 3,000 12,000 22,000 90,500 42,000 152,800 80,000 248,000 4,000 17,200 23,000 94,000 44,000 158,600 85,000 259,500 5,000 22,200 24,000 97,500 46,000 164,000 90,000 270,900 6,000 27,000 25,000 101,000 48,000 169,400 96,000 282,200 7,000 31,700 26,000 104,400 60,000 174,700 100,000 293,300 8,000 36,200 27,000 107,700 62,000 179,800 105,000 304,200 9,000 40,600 28,000 110,900 64,000 184,900 110,000 314,900 10,000 44,800 29,000 114,000 66,000 190,000 115,000 325,500 11,000 48,000 30,000 117,100 68,000 195,000 120,000 336,100 12,000 53,000 31,000 120,200 60,000 200,000 125,000 346,600 13,000 67,000 32,000 123,200 62,000 205,000 130,000 357,000 14,000 61,000 33,000 126,200 64,000 209,900 135,000 367,400 16,000 64,900 34,000 129,200 66,000 214,800 140,000 377,700 16,000 68,800 36,000 132,200 68,000 219,700 145,000 387,000 17,000 72,600 36,000 135,200 70,000 224,500 150,000 398,000 18,000 76,200 37,000 138,200 72,000 229, 300 166,000 408,000 19,000 79,800 38,000 141,200 74,000 234,000 160,000 413,000 7w?»iwrT 360,000 ■ •^320.000- .K 280,000 ■ I J ZWfiOC- I , ■i^zoqooo ■ I I a. ! rrrrrrr f' Ti 120,000 ■ ao.ooo ■ lopoo 30,000. 111069°— 19. (To (ace page 119.) 4^a»3 S0,000. 601,000 70,000 eo,000 90,000 /OO^OOO 110,000 120,000- 130,000 l^,Q0O iSP,0OO' ISQSOO /^■^erage Product/ on per- we// c/ur/n0 Taxab/e Veor. In Barre/s, FIG. 11.— ESTIMATED AVERAGE FUTURE PRODUCTION CURVES, PART OF CALIFORNIA FIELD. MANUAL FOR THE OIL AND GAS INDUSTRY. 119 THE The Kern River field has been one of the most productive per acre in the State. During the year 1918 this field ranked fourth in pro- duction. No records of individual wells were available so the curve pre- sented was made up from the records of the past production of dif- ferent tracts. The curve is applicable to any tract in the field, but estimates made of future production should be made with a full knowledge of the conditions existing on the lease for which the estimate is desired. Estimated future production taJ}le, Kern River oil field. Average Estimated Average production Estmated Average Estimated Average Estimated production average average production average production average per well ftitmre per well future per well future per well future during tax- production during tax- production during tax- production during tax- production able year. per weU. able year. per well. able year. per well. able year. per well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels, t Barrels. Barrels. 1,000 5,600 43,700 11, 500 64,600 17, 500 84,200 1,200 5,600 6,000 46,600 12,000 68,300 18,000 85,800 1,400 10,000 ■6,500 47, 400 12,600 88, 000 18, 600 87, 400 1,600 14,000 7,000 49,200 13,000 69,700 19, 000 89,000 • 1,800 17,000 7,600 51,000 13,500 71,400 19, 500 90,600 2,000 19,800 8,000 S2,700 14,000 73,000 20,000 92,000 2, 800 25, 500 8,500 54,400 14,600 74,600 20,500 93,500 3, 000 30, 000 ?,000 86,100 16,000 76,200 21,000 95, 000 3, 600 33,800 9,600 57,800 16,500 77,800 21, 500 96, 600 4,000 36, 600 10, 000 59,600 IB, 000 79,400, 22,000 98,000 4,600 39,400 10,600 61,200 16,500 81,000' 5,mo 41,700 11,000 62,900 17,000 82,600 SANTA MAHIA FIELD, SANTA BARBARA COUNTY, CALIF. The curve for this field was made up from the production records of different tracts producing in the old Santa Maria field. The Lompoc, Cat Canyon, and Casmalia fields were not included. The records used are of tracts wherein the wells produce from the second and third zones. Some of the wells produce from only one zone, but many produce from both. Estimated future production tofiJe, Old Santa Maria oil field. Average production per well during tax- able year. Estimated average future production per well. Averse production per well during tax- able year. Estimated average future production per well. Average production per well during tax- able year. Estimated average future production per well. Average production per well during tax- able year. Estimated average future production per well. Barrels. 2,000 2,600 3,000 4,000 6,000 «,000 7,000 8,000 9,000 10,000 11, 000 12,000 13,000 14,000 16,000 Barrels. 4,800 9,500 18,800 27,900 37,000 4«,000 54,900 63,600 72, 000 80, 100 88,000 96, 600 102, 900 llfl,000 Barrels. , 16,000 17,000 18,000 19, 000 20,000 21,000 22,000 23,000 24,000 25,000 26,000 27, 000 28,000 29,000 30,000 Barrels. 116, 800 123,300 129,500 136,400 140, 800 145,800 1!)0,500 154,900 159,000 163,000 167:000 170,900 174, 800 178, 500 182, 000 Barrels. 31, 000 32,000 33,000 34,000 35,000 86, 000 37,000 38,000 39, 000 40, OCO 42, 000 44,000 46,000 48,000 50,000 Barrels. 185,300 188,600 191,600 194,600 197,600 200,500 203,400 206,300 209,200 212, 000 217, 400 222, 800 228, 200 233,600 239,000 Barrels, 52,000 64,000 56,000 58,000 60,000 62,000 64,000 66,000 68,000 70, 000 72,000 74,000 76,000 78, 000 80,000 Barrels. 244,200 249, 400 264,600 259, SOO 265,000 269, 800 274, 600 279,400 284,200 289,000 293, 500 298,000 302, 500 307,000 311,500 120 MANUAL FOR THE OIL AND GAS INDUSTRY. VENTURA COUNTY, CALIF. In the region south of the Santa Clara Eiver enough data could be obtained only in one area to prepare an average future production curve. This is the Shields Canyon area, sections 3 and 4, township 3 north, range 19 west. Two sands are productive, but the curve shown is based on the records of individual wells drilled to the upper sand only. Estimated future production table, Ventura field. Average Estimated Average Estimated Average Estimated Average Estimated production average production average production average production average per well future per well future per well uture per well future during tax- production during tax- production during tax- production during tax- production able year. per well. able year. per well. able year. per well. able year. per well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 500 7,600 18,900 16,000 29,300 24,500 37,600 600 1,300 8,000 19,600 16.600 29,800 25,000 38,100 800 3,200 8.500 20,300 17,000 30,300 25,600 38,600 1,000 4,700 9,000 21,000 17,600 30,800 26,000 39,000 1,200 6,800 9,500 21,700 18,000 31,300 26, .500 39,400 1,600 7,200 10,000 22,400 18,600 31,800 27,000 39,900 2,000 8,900 10,500 23,100 19,000 32,300 27,500 40,300 2,500 10,300 11,000 23,700 19,600 32,800 28,000 40,800 3,000 11,400 11,500 24,300 20,000 33,300 28,600 41,200 3,500 12,400 12,000 24,900 20,600 33,800 29,000 41,600 4,000 13,300 12,500 25,500 21,000 34,300 29,600 42,100 4,500 14.200 13,000 26,100 21,600 34,800 30,000 42,600 5,000 15,000 13,600 26,700 22,000 36,300 30,600 43,000 5,500 15,800 14,000 27,300 22,600 35,800 31,000 43,500 6,000 16,600 14,500 27,800 23,000 36,300 31,500 43,900 6,600 17,400 16,000 28,300 23,600 36,700 32,000 44,300 7,000 18,200 16,500 28,800 24,000 37,200 SALT LAKE FIELD, LOS ANGELES COUNTY, CALIF. The Salt Lake field lies between Los Angeles and the Pacific Ocean. The curve shown was prepared from the records of several produc- tive properties in that field instead of from the records of individual wells. The wells in this field produce from the Puente formation, from a zone about 800 feet thick, consisting of the usual alternation of sand, sandy shale and shale. Estimated futui ■e production table, Salt Lake field. Average Estimated Average production Estimated Average Estimated Average Estimated production average average production average production average per well future per well future per well future per well future during tax- production during tax- production during tax- production during tax- production able year. per well. able year. per well. able year. per well. able year. per well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 1,000 21,000 94,800 41,000 136,400 ■ 61,000 163,300 2,000 ' 6,000 22,000 98,000 42,000 138,000 62,000 164,500 3,000 11,800 23,000 101,000 43,000 139,600 63,000 165,700 4,000 17,400 24,000 103,800 44,000 141,100 64,000 166,900 6,000 22,800 25,000 106,400 45,000 142, 600 65,000 168,100 0,000 28,000 26,000 108,800 46,000 144,100 66,000 169,300 7,000 33,200 27,000 111,000 47,000 145,600 67,000 170,500 R,000 38,200 28,000 113,000 48,000 147, 000 68,000 171,700 (1,000 43,200 29,000 115,000 49,000 148,400 69,000 172,900 10,000 48,000 30,000 117,000 50,000 149,800 70,000 174,000 11,000 62,800 31,000 118,800 51,000 151,100 71,000 176,100 12, 000 67,600 32,000 120,600 52,000 152, 400 72,000 170,200 13,000 62,200 33,000 122,400 53,000 163,700 73,000 177,300 11,000 66,800 34,000 124,200 54,000 164,900 74,000 178,400 15,000 71,400 36,000 126,000 66,000 ■166,100 76,000 179,600 16,000 76,800 36,000 127,800 56,000 167,300 76,000 180,600 17,000 80,000 37,000 129,600 . 67,000 158,500 77,000 181,700 l.S.OOO 84,000 38,000 131,400 58,000 169, 700 78,000 182,800 19,000 87,800 39,000 133, 200 69,000 160,900 79,003 183,903 20,000 91,400 40,000 134,800 60,000 162,100 80,000 185,001 spoo IfiOO IS,000 /7fi00 £0,000 ZZ^SOO ZS,000 Z7,SOO 30,000 9Z,S00 3S,000 Averages; RfrocfLrcfion pe>- wefl cfut-lng '7~axab/& Yean, fn Barrels, 37,^00 ^000 111069°— 19. (To face page 121.) FIG. 12.— ESTIMATED AVERAGE FUTURE PRODUCTION CURVES, PART OF CALIFORNIA FIELD. MANUAL FOR THE OIL AND GAS INDUSTRY. WHITTIER FIELD, LOS ANGELES COUNTT, CALIF. 121 In this field nearly all the wells produce from the Puente forma- tion on the southwest side of the Puente fault. There are three fairly- distinct zones and most of the wells penetrate two. The curve shown in figure 12 is based on the action of individual wells in sections 22 and 23, township 2 south, range 11 west. Most of these wells pro- duced from one zone for a number of years and were deepened in 1915 to 1917 to another zone, which restored them to a condition of flush production. For this reason estimates of future production from this curve should be made with caution. Estimated future production table, Whittier field. Average Estimated Average Estimated Average Estimated Average Estimated production overage production average production average production average , per well future per well futm-e per well future per well future during tax- production during tax- production during tax- production during tax- production able year. per well. able year. per well. able year. per well. able year. per well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 400 8,000 27,200 16,600 49,600 24,600 70,100 60O 1,100 8,500 28,600 17,000 60,800 26,000 71,400 800 2,100 9,000 30,000 17,600 62,100 25,500 72,700 1,000 3,000 9,600 31,300 18,000 63,400 26,000 74,000 1,500 5,300 10,000 32,7C0 18,500 64,600 26,500 75,300 2,000 7,300 10,500 34,100 19,000 65,900 27,000 76,600 2,600 9j200 U,000 35,400 19,600 57,200 27,600 77,900 3,000 11,200 11,500 36,700 20,000 58,600 28,000 79,200 3,500 13,100 12,000 37,900 20,600 69,800 28,500 80,400 4,000 14,800 12,500 39,200 21,000 61,100 29,000 81,700 4,500 16,600 13,000 40,600 21,500 62,300 29,600 83,000 6,000 18,200 13,500 41,800 22,000 63,600 30,000 84,300 5,500 19,S0O 14,000 43,100 22,500 04,900 30,500 85,600 6,000 21,300 14,500 44,300 23,000 66,200 31,000 86,900 6,500 22,800 15,000 45,600 23,600 67,600 31,500 88,200 7,000 24,300 15,600 46,900 24,000 68,800 32,000 89,400 7,500 25,800 16,000 48,200 WEST COYOTE FIELD, LOS ANGELES COUNTY, CALIF. The West Coyote field lies a few miles south of the old Whittier field, most of the productive wells having been drilled in sees. 17, 18, 19, and 20, township 3 south, range 10 west, and in sees 13 and 24, township 3 south, range 11 west. The curve shown is based on the records of practically aU the individual wells in that area. 122 MANUAL roa the oil asd gas iwdustbx. Estimated future prodnotion table, We^t Coyote field. Average production Estimated Average Estimated Averaige liistitnated Average EstiniBted average production average production average produotioa average per weli future per well future per well future per well future during tax- production i during tax- production during tax- production during tax- productioa able year. per well. able year. per weU. able year. per well. able year. per well. Barrela. Barrels. Barrels. Sarr^U. Barrels. Barrels. BottAs. Barrels. 2,000 50,000 M0,oao 114,000 206,000 216,000 379,400 4,000 7,200 52,000 143, 700 118,000 208,000 220,000 283,000 6,000 14,300 54,000 147,200 122,800 211,000 216,000 286,780 8,000 21,400 66,000 150,300 126,000 214,000 230,000 290,300 10,000 Sg.SOO 58,000 153,000 130,000 217,000 235,000 293,900 12,000 35,600 60,000. 155,500 134,000 220,000 240,000 297,600 14,000 42,400 62,000 158,000 138,000 223,000 246,000 301,200 16,000 49,200 64,000 160,400 142,000 226,000 250,000 304,800 18,000 55,900 66,000 162,800 146,000 229,000 266,000 308,400 20,000 62, SOD 68,000 166,200 150,000 2^2,000 260,000 312,000 22,000 69,000 70,000 167,500 154,000 234,900 265,000 316,700 24,000 75,400 72,000 169,800 158,000 237,800 270,000 319,300 26,000 81,700 74,000 172,000 162,000 240,700 275,000 322,900 28,000 87,900 76,000 174,100 166,000 243,600 280,000 326,500 80,000 94,000 78,000 176, 100 170,000 246,500 286,000 330,200 32,000 99,800 88,000 178,000 174,000 249,400 290,000 . 334,000 34,000 106,200 82,000 179,800 178,000 252,300 295,000 337,800 36,000 110,200 86,000 183,300 162,000 255,200 300,000 341,500 38,000 116,000 90,000 186,500 186,000 258,100 306,000 346,200 40,000 119,500 94,000 189,700 190,000 261,000 310,000 348,800 42,000 123,800 98,000 192,900 195,000 264,800 315,000 352,400 44,000 128,000 102,000 196,000 200,000 268, 600 320,000 356,000 46,000 132,100 106,000 199,000 205,000 272,200 48,000 136,100 110,000 202,000 210,000 275,800 FULLERTON FIEUJ, LOS ANGELES OOTTNTT, CALIF. This field is sometimes called the La Habra field, and consists of those wells along the eastward extension of the Coyote hills, near Fullerton. Production is obtained from a fairly well defined anti- cline. Figure shows the average future production curve for the average wells of different output in this field. It was prepared from records of individual wells. Estimated fvture prodvction table, Fullerton oil field, La Habra group. Averajte Estimated Average production Estimated Average Estimated Average producUon Estimated production average average production average average per well future per well future per wen fntore per well itutupc during tax- production during tax- production during tax- production during tax- production able year. per well. able year. per well. able year. per well. able year. per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 2,000 20,000 01,500 39,000 104,700 76,000 172,700 2, .500 4,500 21,000 0.3,900 40,000 106,800 78,000 176,100 3,000 9,000 22,000 66,300 42,000 111,000 80,000 179,600 4,000 14,600 23,000 08,700 44,000 115,000 85,000 188,000 5,000 19,500 24,000 71,100 40,000 119,000 90,000 190,000 6,000 23,500 26,000 73,600 48,000 123,000 96,000 204,000 7,000 27,000 26,000 75,800 60,000 127,000 100,000 212,000 8,000 30,000 27,000 78,100 62,000 130,600 105,000 219,600 9,000 32,800 28,000 80,400 64,000 134,200 110,000 227,000 10,000 35,500 29,000 82,700 56,000 137,800 116,000 234,600 11,000 38,200 30,000 85,000 68,000 141,400 120,000 242,000 12,000 40,900 31,000 87,200 60,000 145,000 125,000 249,500 l3,nno 43,600 32,000 89,400 02,000 148,600 130,000 257,000 14,000 46,300 33,000 91,600 64,000 152,000 135,000 264,«)0 15,000 49,000 34,000 93,800 66,000 155,600 140,000 271,500 10,000 61,500 35,000 96,000 68,000 159,000 145,000 278, .500 17,000 64,000 36,000 98, 200 70,000 162,600 I.TO.OOO 285,000 18,000 56,500 • 37,000 100,400 72,000 165,900 155,000 291,500 19,000 69,000 38,000 102,000 74,000 169,300 160,000 298,000 MAS^UAI. FOE THIS OIL AND GAS INDXJSTK¥. OLINDA FIELD, LOS ANGELES COUNTY, CALIF. 123 Figure 12 shows tlie average future production curve for the Olinda field. Production in this field comes from the Puente fault zone and the wells as a rule have rather large future productions for their size. The curve was compiled from aU available records of produc- tion of different tracts. The same caution should he used in making estimates of the future production of wells in this field as are used in other fields. Considemtion should always be given the local condi- tions governing production on the tract for which the estimate is to be made. Estimated future production table, Olinda field. Avierage Estimated Aveua^e Estimated , Average ',. Estimated Average Estimated proaucfion average production average production average production average per well luture par well fatrsie per well Intnre per wen future uring tax- pnoduction during tax- production during tai- production during tax- production daibleyear. per well. aibleyear. : • per well. aMe year. per w«ll. able year. per well. marrOs. -Banets. \ Barrels. BterreU. BarreU. BamU. Barr-els. Barrels. 2,000 13,000 105,000, 24,000 m,,mi 35,000 266,000 3,000 10,000 14,000 114,000 25,000 206,000 36,000 270,000 4,«)0 20,000 15,000 123,000 26,000 213,500 37,2i;Ss::s£::-:::::::-::::-: -h^T-ip:-^H^-^-43X-__-^ OO K--I J 1 L-| 1 1 1 1 fc 1 i___. „-;_.. ^ _l_ 1 1 ) _J 1 J 1 >■■[ |-ii. ^ '"^'-*»^ . _j — ;_ It - ^s^ _ .± _±^ '■"-■«, 't"< jl-^^^ - --^ __ 1. ..^^^^^ j . . .!_ _, — ^. - ^ ^s^_. ., ___ .___ II ■" X X " '^SC X it i ^^-1-- X -_ ^ "" ^S± ' lt_u± - - t o-^K " X + - - i- -C-_ " .- i:. 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FIG. 13.— REPRESENTATIVE CLOSED PRESSURE DECLINE CURVES FOR GAS WELLS AND POOLS IN VARIOUS PARTS OF THE UNITED STATES. SEE PAGES 31 AND 125. 111060° — 10. (To face page 125.) MANUAL FOR THE OIL AND GAS INDUSTRY. 125 In view of the foregoing, the task of estimating the amount of oil in any particular property will be left largely to the taxpayer con- trolling the tract and the Internal Eevenue Bureau will for the present _ confine itself to a critical analysis of the various estimates before issuing any average curves or approximate bench marks on which to base the computation of depletion allowances. In setting up values as of March 1, 1913, or for any subsequent date, for properties in Mexico or any other foreign country, or in computing depletion and depreciation allowances, the same evidence will be required by the Internal Eevenue Bureau as that for prop- erties in the United States, and in filing returns the taxpayer must in all cases append complete evidence supporting all claims. GAS FIELDS OF THE UNITED STATES. Representative decline curves. — On figure 13 are shown selected closed-pressure decline curves for wells, pools, and sands in various parts of the United States. It will be observed first, that the rata of decline varies between wide limits; second, that there are oc- casional temporary rises in pressure; third, that a well or pool may on the one hand " drown out " abruptly, the pressure declining from perhaps several hundred pounds to zero in a few days as the well fills with water, or at the other extreme a well or pool such as the low-pressure wells of Indiana or certain high-pressure wells of Penn- sylvania may decline very slowly over a period of many years. INDEX. Page. Abandonment of wells, pressure at 34 Accounts required, depletion '. 37 Adair district, OlElahoraa 96 Adams County, Ind 89 Allegany County, N. Y 77 Allegheny County, Pa 78 Allen County, Ohio 88 Allocation between depletion and depreciation 20, 21 Allowance : For depletion 12, 22, 31, 32, 66 For depreciation 12, 18, 22 Property paid In and written ofif, etc 13 Reserve for depletion 13 Reserve for depreciation 13 Allowable deductions, cost of development 15 Amended returns, when required 21 Amortization : Definition ot 21 Period 21 Property cost, returnable through 21 Redetermination of, requirements for 1 21 Appalachian region : Future production curves , 80 General outline '. 75 Appraisal, curve method 70 Augusta district, Kansas, estimated future production 94 Avant-Ramona district, Oklahoma, estimated future production 98 Average decline curve 67 Bartlesville-Dewey, Hogshooter district, Oklahoma, estimated future pro- duction 95 Basis : Of depletion deduction 24 Of discovery, revaluation of properties on 40, 41 For deductions . 12 Bath County, Ky 83 Belmont County, Ohio 81 Belrldge field, California 116 Berea sand, Ohio 81 Berea sand. West Virginia 80 Bird Oreek-Skiatook district, Oklahoma 99 Birds Flatrock pool, Illinois 90 Blackford County, Ind 89 Blackwell district, Oklahoma 102 Bona fide sale : Of mines, etc__- 10, 11 Schedule for proof of "^ Boyle's law |1 Bradford sanfl, Pennsylvania J^ Buena Vista Hills, California 115 Buildings, depreciation of o9 Burkburnett field, Texas 104 Butler County, Pa ^ ]^ Caddo oil field lo*. 127 128 INDEX. Paea California oil fields 111 Capital, charges to 41 Capital recoverable through depletion allowance 22 Capital sum, illustration of 14 Capital sum and invested capital, depletion allowance, illustration of effect on . 23 Capital sum returnable through depreciation allowance 19 Carlyle pool, Illinois 89 Casing-head gas contracts, tangible assets 41 Cattaraugus County, N. Y 77 Charges to — Depletion : 74 Expenses 41 Claims, five-year limit for filing 17 Clark County, 111 89 Cleveland district, Oklahoma 98 Clinton County, 111 89 Clinton sand, Hocking and Wayne Counties, Ohio 82 Closed-pressure method : Corrections and refinements 32 For estimating depletion 32 Of gauging 33 Readings to be recorded 34 Season for testing wells 34 Significant details 35 Closing account, depreciation 20 Coalinga Bast Side field, California 118 Coalinga West Side field, California 118 Combined holdings of — Gas properties, depletion allowance, computation of 37 Oil properties, depletion allowance, computation of 36 Computations of allowance for depletion of — Gas wells 29 Oil wells 28 Computation of depreeialion allowances 19 Computation of: Surtax 9 Table of 10 Concrete example, depletion of gas 34 Corrections and refinements, closed pressure method 32 Corsicana field, Texas 103 Cost of deposits, determination of 25 Cost of property as of any specified date, schedule for ascertaining 43 Crawford County, 111 90 Cumberland County, 111 89 Curve : Average decline 67 Decline, symmetrical chnractcr 68 Production, definition of 66 Curves and tables, estimated future production 75 Cushing district, Oklahoma 100 Damages paid, deductible 17 Decline curves . 68 Decline in open fiow capacity, gas 30 Deductible as expenses, development cost, or charged to capital- 15 Deductible, damages paid ; 17 Deduction of charges, time for, on books required 16 Deductions allowable : Bonuses to employees 16 Depletion 22 Dei ireciation . 18 For personal services 15 Individuals 12 Keturn on accrued basis 16 INDEX. 129 Definitions : Page. Amortization 21 Depletion 22 Deiireclation . IS Expenses 15 Fair marliet value 26 Gross income 12 Net income 12 Physical property . 14 Proven oil land 74 Unit cost 28 Dehydrators, depreciation of 57 Dennison pool, Illinois 90 Depletion : Account required 37 Account separate from depreciation 37 Allowance for 12 Capital recoverable through, owner 22, 23 Computation of — For combined holdings of gas properties 37 For combined holdings of oil properties 33 Concrete example of 31 Gas formula 35 Illustration of effect on capital sum and invested capital 23, 24 Mexican fields 124 Apportionment among various sands . 33 Apportionment of deductions between lessor and lessee 24, 25, 29 Basis of deductions 22 For performance record 30 Charges corrected 74 Definition of 22 For years prior to 1916 21 Gas, additional indications of . 31 Lessee entitled to 23 Of gas wells, computations of allowance for 29, 30 Of gas, concrete example 34 Of oil wells, computation of allowance for 2S Of oil or gas claimed, detailed statement to be attached 38 Of oil and gas wells 22 Past years not allowed 42 Reserve distribution from 38 Reserve for 13 Depreciable property 18 Depreciation : Accounts required 37 Allowance 12, 18 Capital sum returnable through 19 Computation of 19 Deductions on books required 20 Reserve 13 Buildings 59 Closing account 20 Computation of 19 Creditable to reserve 18 Definition of IS Dehydrators 57 Drilling equipment 57 Electric equipment 58, 59 For years prior to 1916 21 Improvements 20 Intangible property 19 Machine shop 59 Personal effects not deductible 19 Pipe lines 59. 60 Rates, gas pipe lines 60 111069°— 19 9 130 INDEX. Depreciation — Continued. Vage. Refineries 60 Reserve distribution from 38 Scliedule : 53 Table, rate 04 Tanli cars : 60, 63 Tanks : 58 Tools 58 Transportation equipment 58 Water plants 58 Well equipment 57 De Soto field, Louisiana 100 Details concerning maps 39 Determination of — Cost of deposits 2.1 Quantity of oil 27 Unit cost - 28 Value — Direct methods 49 Fair market 2~> Indirect methods 50 Development costs : Deductible as expense or charsoable to capital ' 15 Inclusions, allowable deductions 14, 15 Direct methods of determining value 49 Discovery : Proof of 40 Schedule for proving principal value, demonstrated ."> Distributing stations 63 Dividend, liquidating 3S Dorseyville pool, Pennsylvania 78 Drilling equipment, depreciation of 57 Economic limit of production 67 Eldorado district, Kansas 93 Electra field, Texas _ 104 Electric equipment, depreciation i)S. -'O Elk Basin field, Wyoming 110 Equal expectations, law of 72 Equipment (see also physical property) 14 Estill County, Ky 84 Estimate required of recoverable oil 27, 28 Estimated future recovery 70-74 Estimating depletion, closed-pressure method for gas 31 Excess-profits tax and war profits 11 Expenses : Charges to -11 Definition of lo Improvements and betterments not deductible as 16 Repairs and replacements 16 Fair market value, definition of 26 Fellows area, Midwayfield, Calif 113 Fictitious price not permissible '2'> Fifth sand, Pennsylvania 78 Filling stations 62 Five-year limit for filing claims 17 Floyd County, Ky 84 Foreword 7-8 Formula, depletion allowance, gas 3'> FuUerton oil field. La Habra group, California 122 Future production, method of estimating GO Future production curves : Appalachian district SO California oil fields 119, 121 Illinois-Indiana field 89 Lima-Indiana field 87 Mid-Continent district 96, 99 Northern Louisiana fields 100 Rocky Mountain fields ■ 109 INDEX. 131 Pago. Future production curves and tables 75 Garber district, Olvlalioma 101 Garfield County, Okla _ loi Gas: Amount of, concrete example 31 Decline curves 125 Decline in open-flow capacity 30 Natural 63 Pipe line, depreciation rate ,f)9 Pore-sp^ce method for estimating supply of 30 Pressure, observation of 31 Gasoline plants, natural gas 64 Gibson County, Ind 90 Glenn pool, Oklahoma 99 Gore pool, Ohio 82 Gordon sand in AVetzel Countj-, W. Va 81 Grant County, Ind 89 Grass Creek, Wyo 110 Gratuities not deductible 16 Gross income, definition of 12 Hancock County, Ohio 88 Harrison County, W. Va 80 Healdton district, Oklahoma 102 Hocking County, Ohio _- 82 Hot Springs County, Wyo 110 Hundred Foot sand, Pennsylvania 78 Huntington County, Ind 89 lUitfois-Indiana field future production curve 80 Improvements and betterments not deductible as expense 16 Improvements, depreciation of 20 Indeterminate losses 17 Inelications of depletion, gas 31 Indirect methods of determining value 50 Individual, normal income tax of 9 Individual, surtax of 9 Insurance companies, deductions special ^ 12 Intangible property, depreciation of 19 Invested capital 14 Irvine pool, Kentucky, estimated future production 85 Jefferson County, Ohio 81 Keener sand, Ohio 82 Kirkwood pool, Illinois 90 Law of averages 71 Law of equal expectations 72 Lawrence County, 111 90 Lease, valuation of fee under 26 Lessee and lessor, apportionment of deductions between 24 Lessee : Capital recoverable through depletion allowance 23 Entitled to depletion 23 Lima-Indiana district = 76 Lima-Indiana field, future-production curves 85 Limit of production, economic 67 Limits on surtax and war excess-profits tax iu case of sale 10 Lincoln County, W. Va 80 Liquidating dividend 38 Losses deductible 17 Losses : Determinate 17 Not deductible 17, 18 liOSt Hills field, California, estimated future production 117 Lucas County, Oliio, estimated future production 88 Machine shop, depreciation of 59 Maps : Details concerning 39 To be submitted '- 39 132 INDEX. Page. Maricopa Flat area, Sunset oil field, California 115 Marion County, Tex 106 Marion County, 111 89 McDonald pool, Pennsylvania 78 McDonougii County, 111 , 90 McKean County, Pa 77 McKittrick field, California 116 Method, appraisal curve 70, 71 Method of— Amortization 21 Computing depletion, gas 30 Estimating future production 68, 70 Estimating recoverable oil reserves 27, 68 Gauging gas, closed pressure 33 Mercer County, Ohio 88 Mexican fields, allowances for 124 Mexican oil fields 123 Storage capacities 124 Transportation facilities 124 Mid-Continent district, future production curves 91 Midway-Sunset field, California 113 Monroe County, Ohio 81, 82 Mooringsport pool, Louisiana 106 Muskogee-Doynton disti'ict, Oklahoma 100 Natural gas 63 Gasoline plants 64 Unit cost 81 Neodesha district, Kansas 94, 95 Net income, definition 12 New Straitsville pool, Ohio 82 Normal income tax of individual 9 Northern Louisiana fields, future production curves 104 Nowata district, Oklahoma 96 Oil and gas wells, depletion of 22 Okmulgee district, Oklahoma 101 Oliuda field, California 123 Osage County, Okla 97 Ottawa County, Ohio . 88 Performance record, basis for gas depletion 30 Period, amortization 21 Perry County, Ohio 82 Personal effects, depreciation not deductible 19 Personal services, compensation for 16 Physical projjerty, definition of 14 Pike County, Ind 91 Pine Island pool, Louisiana 107 Pipe lines, depreciation of 59, 60 Plymouth pool, Illinois 90 Pore-space method for estimating supply of gas 30 Pressure at abandonment of wells . 34 Pressure, observation of gas 31 Production curves, definition of 66 I'roduction curves, plotted , 69 Production, estimates of 112 I'rodui-tive oil zone 111 Proof required in case of sale of mineral deposits 11 Property, cost of, allowable deductions lo I'niperty, cost of, inclusions 15 Pidperty cost returnable through amortization 21 I'roperty, depreciable 18 Property, depreciation of intangible 19 Property, nondepreciable 19 IN0EX. 133 Property paid in anci written off: Page. Reserve for depletion 12, 13 Reserve for depreciation 12! 13 Proven oil land, definition of 74 Quantity of oil, determination of 2T Readings, closed-pressure, significant details 3i5 To be recorded 35 Recoverable oil, estimate required 27 Recoverable oil reserves, methods of estimating 27, 66, 68 Redetermination of amortization 21 Red River field, Louisiana 106, 107 Refineries, depreciation of : 60, 61 Repairs and replacements charged as expense 16 Requirements for amortization 21 Reserve : Distribution from depreciation 38 Depreciation creditable to 18 Return on accrued basis, deductions 16 Revaluation of properties on basis of discovery 40, 41 Revaluation of property, not permissible 26 Revaluation of properties, ruling on 40 Revaluation within 30 days of discovery, allowable 22 Roane County, W. Va 80 Robinson pool, Illinois 90 Rocky Mountain fields, future production curves 107 Sale, limits on surtax and war-excess profits tax in case of 10 Sale of capital assets, schedule for computation of profits or loss from 54 Mineral depoits, surtax on 10 Sale, schedule for proof of 53 Sale of mineral deposits, proof required in case of 11 f^ale of mines, etc., bona fide 10, 11 Sales or marketing equipment 62 ' fjalt Creek field, Wyoming 109 Salt Creek field, first Wall Creek sand 109 Salt Lake field, California 120 Sandoval pool, Illinois 89 Sandusky County, Ohio , 88 San Joaquin Valley, Calif 111 Santa Maria field, California ^ 119 Schedule for ascertaining cost of property 43 Computation of profit or loss from sale of capital assets 54 Depletion 52 Depreciation 53 Proof of bona fide sale 53 Proving principal value demonstrated by discovery :io ' Proof of discovery 51 Valuation of property 47 Season of testing wells, closed pressure 34 Seneca County, Ohio 88 Shinnston pool, West Virginia 80 Siggins pool, Illinois 89 Speechly sand, Pennsylvania 77 St. Marys pool, Ohio 82 Statement to be attached, depletion of oil or gas claimed 38 Sullivan pool, Indiana 91 Surplus, allowance for — Depletion 12, 13 Depreciation 12, 13 Surplus and undivided profits 12, 13 Surtax : Computation of 9 Table of 10 On sale of mineral deposits, Hunts of K' Of individual ^ 134 INDEX. Table : I'aec Depreciation rates, marketing equipment 62 Estimated future production : Adair district, Oklalioma 97 Adams County, Ind 80 Allen County, Ohio 88 Augusta district, Kansas 94 Avant-Ramona district, Oldahoma 98 Bartlesville-Dewey, Hogshooter district, Oklahoma 95 Belridge field, California 110 Berea sand. West Virginia and Ohio 81 Big Injun sand, West Virginia • SO Bird Creek-Skiatook district, Oklahoma 99 Blrds-Flatrock pool, Illinois 90 Blackford County, Ind 89 Blackwell district, Oldahoma 102 Bradford sand, Pennsylvania 77 Buena Vista hills, California 115 Burlvburnett field, Texas 104 Carlyle pool, Illinois 89 Clark County, 111 89 Cleveland district, Oklahoma 9S Clinton County, 111 89 Clinton sand, Hocking and Wayne Counties, Ohio 83 Coallnga, East Side field, California 118 Coalinga, West Side field, California 118 Corsicaua field, Texas 103 Crawford County, 111 90 Ciunberland County, 111 89 Cushing district, Oklahoma 100 Dennison pool, Illinois 90 De Soto field, Louisiana 107 Dorseyville pool, Pennsylvania 78 Eldorado district, Kansas 94 Electra field, Texas 104 Elk Basin field, Wyoming 111 Fellows area, California 114 Fifth sand, Pennsylvania 79 Floyd County, Ky 84 Fullerton oil field. La Habra group 122 Garber district, Oklahoma 101 Gibson County, Ind 90 Glenn pool, Oklahoma 99 Gordon sand in Wetzel County, W. Va 81 Gordou sand in Greene County, Pa 79 Gordon sand in Allegheny County, Pa 79 Gore pool, Ohio 83 Grant County, Ind 89 Grass Creek, Wyo 110 Hancock County, Ohio 88 Healdton district, Oklahoma 102 Hundred foot sand, Ponnsylvania 78 Huntington County, Ind 89 Irvine pool, Kentucky 85 Jackson Ridge pool, Ohio 82 Johnson pool, Illinois 89 Kern River field, California 119 Kirkwood pool, Illiuois 90 Lawrence County, 111 90 Lost Hills field, California 117 Lucas County, Ohio 88 Maricopa Flat area. Sunset oil field, California 115 Jlarion County, 111 89 Jliirion County, Tex lOG McDonough County, 111 00 INDEX. 135 Table — Continued. Estimated future production — Continued. Page. McKittrick field, CaUfornia 116 Mercer County, Oliio 88 Mooringsport pool, Louisiana lOG Muskogee-Boynton district, Oklalioma 100 Keodeslia district, Kansas 95 Nowata district, Oklahoma 96 Okesa district, Oklalioma 97 Okmulgee district, Oklahoma 101 Olinda field, California \ 123 Pike County, Ind 91 Pine Island pool, Louisiana 107 Plymouth pool, Illinois 90 Bagland pool, Kentucky 83 Red River field, Louisiana 107 Robinson pool, Illinois 90 Salt Creek field, first Wall Creek sand, Wyoming 109 Salt Lake field, California 120 Sandoval pool, Illinois 89 Sandusky County, Ohio 8S Santa JIaria field, California 119 Seneca County, Ohio 88 Shinnston pool, West Virginia 80 Siggins pool, Illinois 89 Speech ly sand, Pennsylvania 77 St. Marys pool, Ohio 82 Sullivan County, Ind 91 Twenty-five Hill area, California 114 Upper Lawrence County, 111 90 Tan AVert County, Ohio . 88 Ventura County field, California 120 Vivian pool, Louisiana 106 Wayne County, Ky 84 Wells County, Ind 89 AVest Coyote field, California 122 AVestfield pool, Illinois 89 Whittier field, California 121 Wood County, Ohio ^ 88 Tampico-Tuxpam region, Mexico 123 Tank cars, depreciation of 60 Tanks, depreciation of 58 Tax on corporations for 1918 11 Taxes, deductible 17 Taxes, not deductible 17 Tehuantepec-Tabasco region, Mexico 12H Time for deduction of charges 16 Tools, depreciation of 5S Transportation equipment, depreciation of 58 Ultimate production 71 Underground reserves of oil recoverable, estimate of 66 Unit cost : Definition of 28 Determination of 28 Natural gas 31 Upper Lawrence County, 111 90 Valuation of — Fee under lease 20 Property, schedule for 47 A'aluation, ruling regarding 26 Van Wert County, Ohio 88 Various sands, depletion, apportionment among 33 Ventura County field, California * 320 Vivian pool, Louisiana lOG War-profits and excess-profits tax 11 136 INDEX. I Page. Washington County, Ohio 82 Washington County, Olila 95, 97 Washington County, Pa 79 Wayne County, Ky 84 Wayne County, Ohio 83 Well equipment, depreciation of 57 Wells County, Ind 89 West Coyote field, California 122 Westfield pool, Illinois 89 Wetzel County, W. Va 81 Whittier field, California 121 Wood County, Ohio 88 o ISpk* ^^ t^'»j ^'^^ t i^L ^'' '■f^: