'6. B E R K E L 8 Y^ LIBRARY UNIVWSITY OF CALIFORNIA y EARTH SCIENCW UBRARV S. J-H-f^^^'^l t^e^C-^ ^hUic-ip MANUAL FOR THE OIL AND GAS INDUSTRY UNDER THE REVENUE ACT OF 1918 BY RALPH ARNOLD, J. L. DARNELL and Others NEW YORK JOHN WILEY & SONS, Inc. London: CHAPMAN & HALL, Limited 1920 This monograph is reprinted with the permission of the Oil and Gas Section, Internal Revenue Bureau which issued it as a Bulletin. Cat. ^Qp PRE<;S OF BRAUNWORTH & CO. BOOK MANUFACTURERS BROOKLYN N. V 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 ques- tions that might be asked regarding the law and regulations, and the latter have been amplified when it was deemed necessary to secure the desired result, it is recognized that any such manual is merely suggestive 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 equip- ment and to offer a suggestion as to relative rates of depreciation for different types of physical property. The rates are not to be applied indiscriminately to specific cases, and the Treasury De- partment 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 curves, and a collection of curves and tables covering many of the principal oil pools and fields in the United States. The curves and tables are intended as a suggestio7i 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. They 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. These curves and tables are based upon a careful systematic study of thousands of production records; all that could be made available in the limited time at the disposal of the Bureau. Many 01441 iv FOREWORD refinements and minor corrections are desirable but must be delaj^ed 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 estimates for each property rather than to assume that his par- ticular property is an average. Any or all of the methods dis- cussed 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 produc- tion, but experience has shown that ordmarily these are not likely to cause wide deviation from estimates which have been carefully made. Examination of production records of individual proper- ties will show whether the probability of such occurrences will make estimates unsafe. In cases of apparent hardship to the taxpayer 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 hence- forth the 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 w^as begun before the signing of the armistice, and most of the men who took part in it were called from their usual vocations and under- took the work at a financial sacrifice, and often at great personal inconvenience. 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 their 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. CONTENTS PAOB Foreword iii Introduction xi PART I AMPLIFICATION OF THE LAW AND REGULATIONS. Kinds of taxes imposed 1 Limit on surtax and war-profits and excess-profits tax in case of sale .... 3 Gross income and net income 5 Basis for deductions 5 Invested capital 5 "Capital sum" includes "invested capital" 7 Physical property 9 Cost of property 9 Cost of development 9 General expense 10 Repairs 10 Improvements and betterments 10 Compensation for personal services 11 Bonuses to employees 11 Time for deduction of charges 11 Taxes 12 Losses 12 Depreciation 13 Definition 13 Depreciation allowance 13 Depreciable property 14 Depreciation of intangible property 14 Capital sum returnable through depreciation allowances 15 Method of computing dei)rcciation allowances 15 Modification of method of computing depreciation 15 Charging olT depreciation 16 Closing (leprociation account as to any item 16 Depreciation of imi)rovemcnts in the case of oil and gas wells 17 Depletion and drcpeciation of oil and gas wells in years before 191G. 17 Amortization 18 V vi CONTENTS PAGE Depletion of oil and gas wells 18 Capital recoverable through depletion allowance in case of an owner. 20 Capital recoverable through depletion allowances in the case of lessee . 20 Illustration 21 Apportionment of deduction between lessor and lessee 22 Determination of cost of deposits 23 Determinat ion of fair market value 23 Ruling regarding valuation 25 No revaluation of property permitted 25 Determination of quantity of oil in ground 25 Methods of estimating recoverable reserves 26 Computation of allowance for depletion of oil wells 27 Computations of allowance for depletion of gas wells 29 Methods of computing gas depletion 30 Details of production or the performance record of the well or prop- erty 30 Decline in open-flow capacity 30 Comparison with life history of similar wells or properties, particularly those now exhausted or nearing exhaustion 30 Size of reservoir and pressure of gas or the pore space method 30 Other indications of depletion 31 Closed pressure method 31 Unit costs as applied to natural gas 32 Corrections and refinements of closed pressure method 32 Method of gauging 34 Apportionment of depletion among various sands 34 Season for testing wells for closed pressure 35 Formula 36 Gas well pressure records to be kept 37 Computation of allowance where quantity of oil or gas is uncertain 38 Computation of depletion allowance for combined holdings of oil properties 38 Computation of depletion allowance for combined holdings of gas prop- erties 39 Depletion and depreciation accounts on books 39 Distribution from depletion or depreciation reserve 40 Statement to be attached to a return where depletion of oil or gas is claimed 41 Revaluation of oil or gas properties discovered since March 1, 1913 43 Extract from Regulations 45 43 Charges to capital and to expense in the case of oil and gas wells 46 Depletion for past years not allowed by department 47 Appendix to Part I I. Schedule for ascertaining cost of property as of any specified date . . 47 II. Schedule for the valuation of property as of any specified date. ... 53 III. Schedule for i)roof of discovery 59 IV. Schedule for depiction 61 CONTEXTS Vli PAGE V. Schedule for depreciation 62 VI. Schedule for the proof of bona fide sale 62 VII. Schedule for computation of profit or loss from sale of capital assets ti4 VIII. Schedule for proving that the principal value has been demon- strated by prospecting or exploration and discovery work done by the taxpayer 65 PART II ESTIMATE OF DEPRECIATION OF EQUIPMENT USED IN THE OIL AND GAS INDUSTRY Preface to Part III 67 Class A, No. 1, drilling equipment 68 Class A, No. 2, well equipment 68 Class A, No. 3, dehydrators 69 Class A, No. 4, tanks 69 Class A, No. 5, tools 70 Class A, No. 6, transportation equipment 70 Class A, No. 7, water plants 70 Class A, No. 8, electric equipment 70 Class A, No. 9, machine shop 71 Class A, No. 10, buildings 71 Class B, pipe lines 71 Class C, tank cars 72 Class C, refineries 72 Calculated depreciation for whole refinery 73 (a) Complete refinery 73 {h) Skimming i)lant 73 Sales or marketing equijjment 75 Natural gas utility companies 76 Natural gas gasoline plants 77 Summary 78 PART III ESTIMATE OF RECOVERABLE UNDERGROUND RESERVES OF OIL Preface 80 Section A. Methods 83 Section B. Average future production curves and tables 92 Appalachian district 92 Lima-Indiana and Illinois districts 107 Midcontinont district 117 North Louisiana district 130 Rocky Mountain district 141 California district 146 (julf (toast of Texas and Louisiana 16r» Gulf Coast Oil Fields 167 Mexico ar.d other foreign countries 173 ILLUSTRATIONS Fui. 1. (.'iirvps illu.strsitin^ methods St 2. r!iirvos illii.stnitiiif>; niethnds Sf) •i. Curves illiisl rutins: (hciIkkI-! 88 -4. Future production curves, A|)])alaehi;m iield 99 o. Future production curves, Lima-Iiuliana field 110 G. Future production curves, Illinois-Indiana field W.i 7. Future production curves, Mid-continent field I'il 8. Future jn'oduction curves, Mid-coiiliiienl field 128 9. Future product ion curves, northwest Louisiana Held i:?S 10. Future production curves. Rocky Mountain field 14)} 11. Future production curves, Caliiornia field 1")9 12. Future production curves, Caliiornia field 1<>2 l;j. Cas decline curves 17(i Future production curve, Humble field U)7 Future i)roduction curves, Humble antl Goose Creek fields 169 Future production curve, Saratoga field 170 Future production curves, Saratoga and Edgerlev fields 171 I'^ilinc pidduclioii curves, Bafson, Fvangeline, Sour Lake and \inlon fields 172 INTRODUCTION This Manual was first issued by the Bureau of Internal Rev- enue of the Treasury Department in Februaiy, 1919, shortly after the passage of the Revenue Act of 1910. The original edition of 10,000 copies was soon exhausted, and the demand for the book has become so great that the present private reprint, bringing certain features up to date, has been decided upon. The volume was prepared to assist the taxpayer of the oil and gas industiy in correctly and expeditiously preparing his Federal tax returns. Although the endeavor was made to anticipate all questions that might be asked regarding the law and regulations, and the latter were amplified when it was deemed necessary to obtain the desired result, it is recognized that such a manual is only general and cannot cover all cases that may exist. The Manual is based largely upon information gathered during the Fall of the year 1918 by a corps of geologists, technologists and engineers. The investigation was undertaken primarily to furnish a basis for arriving at valuations, and dcleption and depreciation deduc- tions in connection with oil and gas properties. Deeming these subjects to be of the greatest importance, the Bureau of Internal Revenue instituted a most careful inquiry. All fields in the United States were canvassed. Records of production of thou- sands of properties were collected and tabulated. These were carefully classified and studied by the most competent and experi- enced men in the country and the average future production curves and tables of valuation data were produced as a result of this study. In compiling the Manual, the country was divided into seven districts, each of which was handled by a supervisor and several assistants. These were the xii INTRODUCTION Appalachian Field. — G. B. Richardson, of the U. S. Geological Survey, assisted by Barniim Brown, L. C. Glenn, Roswell H. Johnson and others. Lima-Indiana and Illinois Fields. — Thos. E. Savage, Super- visor, assisted by J. L. Darnell, L. G. Donnelly and others. Mid-Continent Field. — J. 0. Lewis, Supervisor, assisted by H. B. Goodrich, Calvin T. Moore, James H. Hance, W. E. Wrather and others. Northern Louisiana Field. — A. Faison Dixon. Gulf Coast Field. — E. DeGolyer, Supervisor, assisted by A. Faison Dixon, M. W. Mattison and others. The Rocky Mountain District. — Cassius A. Fisher, Supervisor, assisted by Arthur Eaton, C. W. Comstock and others. California. — Carl H. Beal, Supervisor, assisted by N. R. White, E. D. Nolan, Robert B. Moran and others. The foreign countries including Mexico were covered by V. R. Garfias. The natural gas industry was handled by E, W. Shaw of the U. S. Geological Survey, assisted by S. S. Wyer, A. J. Diescher, W. J. Judge, W. A. Williams, T. B. Gregory, F. R. Clark, E. H. Finch and K. D. White. The book consists of three parts. Part I deals directly with the Law and Regulations. These as they relate to the oil and gas industry, are explained and nu- merous illustrations and examples are given to bring out their appli- cation. Since the issuance of the original edition of the Manual the regulations relating to discovery, proven tract or lease, prop- erty disproportionate in value and proof of discovery (Art. 220a and 221) have been altered by the adoption of Treasury Decision 2956 (December 2, 1919.) The new regulations regarding these subjects are printed on pp. 44 to 46. Part II deals with the question of depreciation and is the result of the work of a committee of which W. A. Williams, of the Fuel Administration, was chairman, assisted by Thos. Cox, A. W. Ambrose, H. H. Hill, J. P. Smoots of the Bureau of Mines and L. G. Donnelly of the Bureau of Internal Revenue. This chapter should assist the taxpayer in standardizing his classifi- cation of equipment. It also offers suggestions as to relative rates of depreciation for different types of physical property. The rates are not to be applied indiscriminately to specific cases INTRODUCTION xui but are relative only and the Treasury Department is in no way committed to accept them in the returns. Part III consists of descriptions and methods of estimating underground oil reserves, especially by means of productive curves. The principal paper in this chapter is by J. 0. Lewis and C, H. Beal of the United States Bureau of Mines, whose work along this same line is well known to petroleum engineers throughout the country. A collection of curves and tables covering many of the oil fields and pools in the United States accompanies the text. In the case of the individual districts, these curves and tables were prepared under the supervision of the men in charge of the dis- tricts in which the pools and fields are situated. The curves and tables relating to the Gulf Coast fields were not included in the original Manual; the tables were issued subsequently in pam- phlet form; the curves have been prepared from the tables especi- ally for this present edition. The curves and tables are intended as a suggestion for the guid- ance of the taxpayer in the computation of his depletion allow- ance, which in turn has a direct bearing on the amount of his tax. They are not to be applied indiscriminately to specific prop- erties, and the Treasury Department is in no way committed to accept estunates based upon them. Every clami for deduction on account of depletion must be accompanied by a detailed state- ment of production, etc., upon which such claim is based. One of the principal reasons for reprinting the INIanual was the desire to continue the availability of the curves and tables which have so many other uses besides that of forming a basis for tax computa- tions. Among these uses might be mentioned appraisal work on properties and fields, estimation of life of properties and fields, comparative study of the productivity and rate of decline of fields, etc. The curves and •tables are based upon a careful systematic study of thousands of production records ; all that could be made available in the limited time at the disposal of the Bureau. ]\Iany refinements and minor corrections are desirable, but must be delayed until more complete records are in hand. The work of compiling and editing the material in the manual was done largely by A. D. Brokaw, J. L. Darnell and L. G. Don- nelly. The investigations leading to the preparation of the man- ual and its compilation and publication were under the general xiv INTRODUCTION supervision of the writer, then Chief of the Oil and Gas Section. Following the resignation of the writer, J. L. Darnell was made Chief of the Natural Resources Branch of the Internal Revenue (including Oil and Gas), he holding the position until March 1, 1920, when he was succeeded by J. C. Dick. Those taking part in the collection and compilation of the material on which the Manual is based, in addition to those already mentioned are : California Field: Carl H. Beal. Blackmar, C. A., Hall, L. S.; Johnson, H. R.; Moran, R. B.; Nolan, F. P.: Gibson, E. J.; Arrell, D. B.; White, N.R.; Kingsberrv. J. W. : Boyd, H.; Clute, W. S.; Campbell, Harry; Trengrove, S. R. Rocky Mountain Field : C.A.Fisher. Lewis, J. W.; Patton, H. B.; Eaton, Arthur; Prommel, H. W.; Comstock, Chas. W. ; Prather, R. C; Olds, Thos. H. Mid-Continent Field: J. 0. Lewis. Richards, Ralph; Samp- son, C. E.; Hance, J. H.; Wrather, W. E.; Hammer, A. A.; Lloyd, E. R., U. S. G. S.; Goodrich, H. B.; Taylor, C. H.; Moore, C. T.; McKnight, R. J.; St. Clair, Stuart; BUsingame, Wade A.; Caudill, S. J. Gulf Field: E. DeGolyer and A. F. Dixon. Hopkins, O. B.; Mattison, M. W.; Prather, W. W. ; Garfias, V. R. ; Springer, A. R. ; Bentley, W. T.; Kupferstein, J. T. lUinois and Lima-Indiana; T. E. Savage. Donnelly, L. G.; McConnell, K.; Darnell, J. L.; Henney, T. V.; Franklin, Louis; Lines, E. F.; Dawson, Dan; Barrett, Edw.; Blatchley, R. S.; Kahn, J. B.; White, K.D.; Morgan, D.M.; Herald, F. A.; Camp- bell, R. M.; Welsh, LeRoy G.; Rasmus, Walter; Cox, Eugene G.; Eskil, Rolf M.; Pengilly, H. E.; Duval, Wm. C. Appalachian Field: Geo. B. Richardson. Glenn, L. C; Stout, W.; Ports, P. L.; Brown, Barnum; Hoeing, J. B.; Melcher, A. F. ; Miller, A.M.; McElroy, S. M.; Johnson, R. S. H.; Miller, M.M.; Johnson, F. Arthur; Herzig, J. A., Rev. Agt. ; Bender, W. J., Rev. Agt.; Bernard, G. A., Rev. Agt.; Jillson, M. R.; Stephen- son, E. A. Gas Fields: E. W. Shaw. Clark, F. R.; Moore, R. C; Wrather, W. E.; Lee, W. T.; Patton, H. B.; Finch, E. H. MANUAL FOR THE OIL AND GAS INDUSTEY PART I. AMPLIFICATION OF THE LAW AND REGULATIONS. KINDS OF TAXES IMPOSED. The Revenue 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 following 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: Pro- vided, 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 unposed 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 cohmm of the table is to be excluded and the second figure included. The percentage given opposite applies to the excess of income over the first figure in the net-income column, and the simi in the next colunm is the tax on the entire difference between the first figure and the second figure in the net-income column. The final column gives the total surtax on a not income q(\\ il to the second figure in the nel -income MANUAL FOR THE OIL AND GAS INDUSTRY Net Income. $5,000 to $0,000.... $6,000 to $8,000 $S,000 to $10,000 $10,000 to $12,000 $12,000 to $14,000 .. . $14,000 to $16,000 $16,000 to S18,000 $18,000 to $20,000 $20,000 to $22,000 $22,000 to $24,000 $24,000 to $26,000 $26,000 to $28,000 . . . . $28,000 to $30,000 $30,000 to $32,000 $32,000 to $34,000 $34,000 to $36,000 $36,000 to $38,000 $38,000 to $40,000 $40,000 to $42,000 $42,000 to $44,000 $44,000 to $46,000 $46,000 to $48,000 $48,000 to $50,000 $50,000 to $52,000 $.'52,000 to $54,000... . $.54,000 to $56,000 $56,000 to $58,000 $58,000 to $60,000.. . . $60,000 to $62,000 $62,000 to $64,000 $64,000 to $66,000 $66,000 to $68,000 $68,000 to $70,000 $70,000 to $72,000 $72,000 to .$74,000 $74,000 to $76,000 $76,000 to $78,000 $78,000 to $80,000 $80,000 to $82,000 $82,000 to $84,000 $84,000 to $86,000 $86,000 to $88,000.. . . $88,000 to .$90,000 $90,000 to $92,000 $92,000 to ,W4,000 $94,000 to $90,000 $96,000 to $98,000 $98,000 to $100,000... $100,000 to $150,000.. $1.50,000 to $200,000.. $200,000 to $300,000. . $300,000 to $500,000. . $500,000 to $1,000,000 $1,000,000 up Per Cent. Surtax. Total Surtax. 1 $10 $10 2 40 3 60 110 4 80 190 5 100 290 6 120 410 7 140 550 8 160 710 9 180 890 10 200 1,090 11 220 1,310 12 240 1,550 13 260 1,810 14 280 2,090 15 300 2,390 16 320 2,710 17 340 3,050 18 360 3,410 19 380 3,790 20 400 4,190 21 420 4,610 22 440 5,050 23 460 5,510 24 480 5,990 25 600 6,490 26 520 7,010 27 540 7,550 28 560 8,110 29 580 8,690 30 600 9,290 31 620 9,910 32 640 10,550 33 660 11,210 34 680 11.890 35 700 12,590 36 720 13,310 37 740 14,050 38 760 14,810 39 780 15,590 40 800 16,390 41 820 17.210 42 840 18,050 43 860 18,910 44 880 19,790 45 900 20,690 46 920 21,610 47 940 22,550 48 960 23,510 52 26,000 49,510 56 28,000 77,510 60 60,000 137,510 63 126,000 263,510 64 320,000 583,510 65 MANUAL FOR THE OIL AND GAS INDUSTRY 3 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 "^he excess over that amount at the rate indicated in the table. For example, if the amount of net income is S63,128, 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. LIMITS OF SURTAX AND WAR EXCESS PROFITS TAX IN CASE OF SALE. Sections 211 (b) and 337 of the Revenue Act of 1918 provide that "in the case of a bona fide sale of mines, oil or gas wells, or any interest therein, where the principal value of the property has been demonstrated by prospecting or exploration and discovery work, done by the taxpayer, the portion of the tax imposed by this section attributable to such sale shall not exceed 20 per cent of the selling price of such property or interest." Regulations 45, article 13 — "Surtax on the sale of mineral ddosits. — ^Where the taxpayer by prospecting and locating clamis, or by exploring and discovering undeveloped claims, has demon- strated the principal value of mines, oil or gas wells, which prior to his efforts had a merely nominal value, the portion of the surtax attributable to a sale of such property or of the taxpayer's interest therein shall not exceed 20 per cent of the selling price. Explora- tion work alone without discovery is not sufficient to bring a case within this provision. Shares of stock in a corporati on owning mines, o il or gas wells do not constitute an interest in such property^ To determine the application of this provision to a particular case, the taxpayer should first compute the surtax in the ordinary way upon his net income, including his net income from any such sale. The proportion of the surtax indicated by the ratio which the taxpayer's net income from the sale of the property, computed as prescribed in article 715 of Regulations 45, bears to his total net income is the portion of the surtax attributable to such sale, and if it exceeds 20 per cent of the selling price of the property such portion of the surtax shall be reduced to that amount." In the case of a corporation the war and excess profits tax applicable to such a sale is limited to 20 per cent of the selling price in accordance with section 337 of the law. 4 MANUAL FOR THE OIL AND GAS INDUSTRY What the Taxpayer Must Prove. The taxpayer in order to take advantage of this clause in the law must prove — (q) A bona fide sale. X&) That the principal value of the property has been demon- strated by prospecting or exploration and development work done by the taxpayer. This benefit will accrue only to the holdings of the taxpayer making the discovery. In order to meet the requirements of the case to the satis- faction of the Commissioner, the taxpayer will be required to sub- mit the information called for in Schedules III, VI, and VIII on pages 59, 62, and 65 of the Manual. Tax On Corporations} Section 230 of the Revenue Act of 1918 levies, in lieu of the taxes imposed by section 10 of the Revenue Act of 1916, as amended by the Revenue Act of 1917 and by section 4 of the Revenue Act of 1917, upon the net income of every corporation not specifically exempted a tax at the following rates : (1) For the calendar year 1918, 12 per cent of the amount of the net income in excess of the credits provided in section 236; and (2) For each calendar year thereafter 10 per cent of such excess amount. See Part II of the Regulations, War-Profits and Excess-Profits Tax. Section 301 (a) of the Revenue Act of 1918 levies, in lieu of the tax imposed by Title II of the Revenue Act of 1917, but in ad- dition to the other taxes imposed by this act, upon the total net income of every corporation not specifically exempted, for the tax- able year 1918 a tax equal to the sum of the following: First bracket. — Thirty per cent of the amount of the net income in excess of the excess profits credits (as determined under sec. 312) and not in excess of 20 per cent of the invested capital. ' In all cases involving returns of corporations Part II of Regulations 45 ehould be consulted. MANUAL FOR THE OIL AND GAS INDUSTRY 5 Second bracket. — Sixty-five per cent of the amount of the net income in excess of 20 per cent of the invested capital. Third bracket. — ^The simi, if any, by which 80 per cent of the amount of the net income in excess of the war-profits credits (determined under sec. 311) exceeds the amount of the tax com- puted under the first and second brackets. See Part II of the Regulations. 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 Revenue Act of 1918, actually re- ceived 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 deduc- tions (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 avoid confusion in making returns. In general, the deductions from gross income allowed cor- porations are the same as allowed individuals, except that corpora- tions may deduct dividends received from other corporations sub- ject 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 Revenue Act of 1918 as^(l) 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 iwrncd surplus and undivided profits, not including surplus and un- divided 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 Reg- 6 MANUAL FOR THE OIL AND GAS INDUSTRY ulations 45. Several of the articles which must ordinarily be con- sidered are set out below. Regulations 45, article 839. Surplus and undivided profits: Allowance for depletion and depreciation. — Depletion, like depre- ciation, must be recognized in all cases in which it occurs. Deple- tion attaches to each unit of mineral or other property removed, and the denial of a deduction in computing net income under the Act of August 5, 1909, or the limitation upon the amount of the deduction allowed under the Act of October 3, 1913, does not relieve the corporation of its obligation to make proper provision for depletion of its property in computing 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 depreciation or depletion written off in prior years was insuffi- cient or excessive, as the case may be. Where deductions for depreciation or depletion have 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 expendi- tures have been charged to expense in lieu of depreciation or de- pletion, 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 m 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 deduc- tion for any depreciation, obsolescence, or depletion; and (2) The aggregate amount mcluded 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 depre- ciation or for depiction are included in the surplus account it MANUAL FOR THE OIL AND GAS INDUSTRY 7 should be analyzed so as to separate reserves and leave only real surplus. Reserves for depreciation or depletion can not be in- cluded in the computation of invested capital, except to the follow- ing extent : (1) Excessive depletion or depreciation included therein and which if charged off could be restored under article 871 ma y be include d in t he 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 depreciation or depletion representing the realization of appre- ciation of value at March 1, 1913, or such subsequent date may, if undistributed and used or employed in the business, be treated as surplus and included in the computation of in vested capi tal. 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 accordingly. 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 capital, and if already reflected in the surplus account it must be deducted there- from. The term Cajntal Sum is here applied to the total amount re- turnable to the taxpayer through depletion, depreciation, and qb-^ 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). "CAPITAL SUM" AND "INVESTED CAPITAL." The "capital sum" has no necessary relation to the "invested capital." It may represent the investment of funds belonging to the taxpayer, or the investment of l)orrowed fimds, which have no relation to invested capital ; under the provisions of the law and regulations, the capital sum may include amounts based upon the right of valuation as of March 1, 1913, or within 30 days after the \ 8 MANUAL FOR THE OIL AND GAS INDUSTRY discovery of oil or ^as by the taxpayer. (See Proof of Discovery, page 45.) Where such valuations are allowable, they have no application to invested capital, except in accordance with article 844 (2) of Regulations 45, and may not be used for any purpose other than j,s a basis for depletion, depreciation, and obsolescence, or as a basis upon which to determine the gain or loss arising from the sale or surrender of property acquired prior to March 1, 1913. With respect to any allowance for amortization the basis is the cost of property acquired after April 5, 1917, and no amount may be added on account of revaluation. The application of these principles is indicated in the following: A corporation had a paid-up capital stock of $50,000. This amount was invested in oil and gas property and in addition the corporation had incurred liabilities due to developing the property and the purchasing of equipment at the beginning of the taxable year amounting to $50,000. The property was found to have a value of $150,000 in accordance with the valuation accepted by the Commissioner. The allowable deductions for depletion and depre- ciation in determining the net income of the corporation are com- puted on the value of $150,000. The actual invested capital for the purpose of calculating the tax due for the taxable year from the corporation is $50,000. However, in the succeeding taxable year a part of the aggregate allowance for depletion and depreciation (proportionate to the part of the capital smn representing appre- ciation) may be included in invested capital in accordance with the provision of article 844 (2) of Regulations No. 45. The following statement is prepared to illustrate the application of the law to the case cited: Assuming the total deduction for depletion, depreciation, and oboles- cence from the gross income to be 10 per cent of the valuation accepted by the Commissioner, the amount deductible for the tax- able year would be : $15,000 Amount of depiction, depreciation, and obsolescence calculated on the cost of the property is 10,000 The amount of realized appreciation which may be added to invested capital for the succeeding year is 5,000 Assuming that all the earnings are distributed, except the depletion and depreciation reserves, at the beginning of the succeeding tax- able year, the invested capital would be 55,000 The cost of the property would be 90,000 The ai)i)rcciation in value would be 45,000 MANUAL FOR THE OIL AND GAS INDUSTRY 9 Physical property is defined as all equipment having an inven- tory or salvage value and subject to removal from the property, such as buildings, bridges, and power plants; derricks, c^ings^ drilling equipment (cable and rotary), and pumping equipment, including engines, boilers, tubing, and rods; flow lines, and con- nections on wells, tanks_attached to wells, and other tankage_of steel, wood, or concrete; cleaning and pulling equipment; salt^ water equipment; refineries, treating and reducing plants, includ- ing casinghead gas plants; telegraph and telephone lines, pipe lines and tank cars, and all other equipment used in the produc- tion^ reduction, conservation, or transportation of oil and gas or their products. Cost of property includes all amounts (in cash or its equivalent) paid for and incident to the esta])lishment of title and acquisition of the lease or freehold, as the case may b e, su ch as^— Purchase price of lease or freehold. Sal aries or commissions paid to brokers or agents. Fees to geologists, attorneys, surveyors, etc., for examination and defense of title, establishing boundaries, etc., State^ and county fees for recording and legalizing transfers, and all other payments made in acquiring and establishing title to the properties. Cost of development comprises all payments made for and incident to the drilling of wells, such as cost of — (1) Physical property. (2) Geological and other surveys, made subsequent to ac- quisition. (3) Roads. (4) Water supplies. (5) Hauling. (6) Wages. (7) Drilling. (8) Shooting. (9) Overhead charges ^incident to drilling of wells). (10) Fuel; and (11) All other similar expenditures^ Both "Cost of Property" and "Cost of Development," in so far as they have not been decreased by allowable deductions, are chargeable to capital sum and are returnable through the several allowable deductions. Structures and equipment may also be i nclu ded in capital assets and arc returnable through depreciation, 10 MANUAL FOR THE OIL AND GAS INDUSTRY In the case of revaluations as of March 1, 1913, or within 30 days of a discovery ])y the taxpayer made subsequent to February 28, 1913, th(^ \:ilu(' thus cslabhshed phis subsequent costs not other- wise deducted becomes the total of "Capital Sum.'' This revalu- ation, however, does not affect the Invested Capital, as explained on page 7. Development costs (except the cost of physical property) may be deducted as an expense in the year in which they are paid out or at the option of the taxpayer may be charged to capital sum. Election once made under this option is final and will control the returns for all subsequent years. EXPENSES. Expense includes all amounts paid out (exclusive of amounts paid for physical property and development charged to Capital Sum) incident to the development and operation of producing properties and the preparation of their product for market, such as costs of pumping, cleaning, reshooting (including cost of torpedoes), gauging, storing, treating, reducing, repairs and maintenance, transporting, refining, conserving, marketing, overhead expense, insurance, etc. The cost of repairs and replacements made necessary through deterioration of equipment may be charged off as expense, but if this is done the amount allowed as a depreciation deduction will be reduced. In all cases items of expense must be charged off as such for the year incurred and can neither be deducted from the income of sub- sequent years as expense nor added to Capital Sum. Repairs. — The cost of incidental repairs which neither mater- ially add to the value of the property nor appreciably prolong its life, but keep it in an ordinary efficient operating condition, may be deducted as^xj)ense, pr ovid ed the plant or property account is not increased by the amount of such expenditures. Repairs in the nature of replacements, to the extent that they arrest deteriora- tion and appreciably prolong the life of the property, should be charg(Hl against the depreciation reserve. Improvements and betterments. — Amounts expended for additions and betterments or for furnitm-e and fixtures, which constitute an increase in capital assets or add to their value, are MANUAL FOR THE OIL AND GAS INDUSTRY 11 not a proper deduction, but such expenditures when capitalized may be reduced through annual depreciation d eductions. COMPENSATION FOR PERSONAL SERVICES. Among the ordinary and necessary expenses paid or incurred in carrying on any trade or business may be included a reasonable allowance for salaries or other compensation for personal services actually rendered. The test of deductibility in the case of com- pensation payments is whether they are reasonable and are in fact payments purely for services. Bonuses to employees. — Gifts or bonuses to employees will constitute allowable deductions from gross income when such payments are made in good faith and as additional compensation for the services actually rendered by the employees, provided such payments, when added to the stipulated salaries, do not exceed a reasonable compensation for the services rendered. Donations made to employees and others, which do not have in them the element of compensation or are in excess of reasonable compensation for services, are considered gratuities and a re not d eductible from gross i ncome. TIME FOR DEDUCTION OF CHARGES. Each year's return, so far as practicable, both as to gross income and deductions therefrom, should be complete in itself, and tax- payers are expected to make every reasonable effort to ascertain the facts necessary to make a correct return. The expenses, liabilities or deficit of one year can not be used to reduce the income of a subsequent year. A person making returns on an accrued basis has the right to deduct all authorized allow- ances, whether paid in cash or set up as a Hability, and it follows that if he does not within any year pay or accrue certain of his expenses, interest, taxes, or other charges, and make no deduction therefor, he can not deduct from the income of the next or any subsequent year any amounts then paid in liciuidation of the previous year's liabilities. A loss from theft or embezzlement occurring in one year and discovered in another is deductible only for the year of its occurrence. Any amount paid pursuant to a judgment or otherwise on account of damages for personal injuries, patent infringements, or 12 MANUAL FOR THE OIL AND GAS INDUSTRY otherwise, is deductible from gross income when the claim is liquidated or put in judgment or actually paid, less any amount of such damages as may have been compensated for by insurance or otherwise. If subsequent thereto, however, a taxpayer has for the iSrst time ascertained the amount of a loss sustained during a prior taxable year and not deducted from the gross income therefor, he may render an amended return for such preceding taxable year, including such amount of loss in the deductions from gross income, and may file a claim for refund for the excess tax paid by reason of the failure to deduct such loss in the original return. Provided that no such credit or refund shall be allowed or made after five years from the date when the return was due, unless before the expiration of such five years a claim therefor is filed by the tax- payer. TAXES. Federal taxes (except income, war-profits, and excess-profits taxes), State and local taxes (except taxes assessed against local benefits of a kind tending to increase the value of the property assessed), and taxes imposed by possessions of the United States or by foreign countries (except the amount of income, war-profits, and excess-profits taxes allowed as a credit against the tax), are deductible from gross income. See section 222 of the statute and articles 381 et seq. of Regulations 45 as to tax credits. Postage is not a tax. Amounts paid to States under secured- debts laws in order to render securities tax exempt are deductible. Automobile license fees are ordinarily taxes. LOSSES. Losses sustained during the taxable year and not compensated for by insurance or otherwise are fully deductible (except by non- resident aliens) if — (a) Incurred in the taxpayer's trade or business; (6) Incurred in any transaction entered into for profit; or (c) Arising from fires, storms, shipwreck, or other casualty, or from theft. They must usually be evidenced by closed and completed trans- actions. In the case of the sale of assets the loss will be the differ- ence between the cost thereof, less depreciation sustained since MANUAL FOR THE OIL AND GAS INDUSTRY 13 acquisition, or the value as of March 1, 1913, if acquired before that date, less depreciation since sustained, and the price at which they were disposed of. When the loss is claimed through the destruction of property by fire, flood, or other casualty, the amount deductible will be the difference between the cost of the property; or its value as of March 1, 1913, and the salvage value thereof, after deducting from the cost or value as of March 1, 1913, the amount, if any, which has been or should have been set aside and deducted in the current year and previous years from gross income on account of depreciation, and which has not been paid out in making good the depreciation sustained. But the loss should be reduced by the amount of any insurance or other compensation received. Losses in illegal transactions are not deductible. Losses of oil and gas are of two kinds: (a) Those which arc unforeseen or unavoidable, such as losses sustained through fire or accident; and (b) losses that are anticipated and recognized as unavoidable under operating conditions, such as evaporation of oil in storage, ordinary leakage, refinery losses, etc. Usually the latter class are indeterminate as to amount and are absorbed either implicitly or explicitly in current operating ex- penses or in cost of the oil or gas. Indeterminate losses may not be d educted from gross in co me. DEPRECIATION. Quotation from law. — Section 214 (a) (10): In the case of mines, oil and gas wells, other natural deposits, and timber a / reasonable allowance for depletion . . . and for depreciation of imjirove- ments, according to the peculiar conditions of each case, based upon cost including cost of development not otherwise deducted. Definition.^ — ^The term depreciation is used to cover the waste of assets due to exhaustion, wear and tear, and obsolescence of property, and is not to be confused with the depletion of the natural deposits of oil and gas due to the removal of these com- modities in the course of exploitation of any property. Depreciation Allowa7ice. Regulations 45, article 161. — A reasonable allowance for the exhaustion, wear and tear, and obsolescence of property used in 14 MANUAL FOR THE OIL AND GAS INDUSTRY tlic tra(l(^ or business may be deducted from gross income. The proper allowance for such depreciation of any property used in the trade or business is that amount which should be set aside for the taxable year in accordance with a consistent plan by which the aggregate of such amounts for the useful life of the property in the business will suffice, with the salvage value at the end of such useful life, to provide in place of the property its cost or its value as of March 1, 1913, if acquired by the taxpayer before that date. Depreciable Property. Regulations 45, article 162. — The necessity for a depreciation allowance arises from the fact that certain property used in the business gradually approaches a point where its usefulness is exhausted. The allowance should be confined to property of this nature. In the case of tangible property it applies to that which is subject to wear and tear, to decay or decline from natural causes, to exhaustion, and to obsolesence due to the normal progress of the art or to becoming inadequate to the growing needs of the business. It does not apply to inventories or to stock in trade, nor to land apart from the improvements or physical development added to it. It does not apply to bodies of minerals which through the process of removal suffer depletion, other provisions for this being made in the statute. Property kept in repair may, nevertheless, be the subject of a depreciation allowance. The deduction of an allow- ance for depreciation is limited to property used in the taxpayer's trade or business. No such allowance may be made in respect to automobiles or other vehicles used chiefly for pleasure, a building used by the taxpayer solely as his residence, nor in respect of furniture or furnishings therein, personal effects, or clothing; but properties and costumes used exclusively in a business, such as a theatrical business, may be the subject of a depreciation allowance. Depreciation of Intangible Property. Regulations 45, article 163. — Intangibles, the use of which in the trade or business is definitely limited in duration, may be the subject of a depreciation allowance. Examples are patents and copyrights and limited leases, licenses, and franchises. MANUAL FOR THE OIL AND GAS INDUSTRY 15 Capital Sum Returnable through Depreciation Allowances. Regulations 45, article 165. — The capital sum to be replaced by- depreciation allowances is the cost of the property in respect of which the allowance is made, except that in the case of property accLuiredJby the taxpayer prior to March 1, 1913, the capital sum to be replaced is the fair market value of the propert y as of tha t date. In the absence of proof to the contrary, it will be assumed that such value as of March 1, 1913, is the cost of property less depreciation up to that date. To this sum should be added from time to time the cost of improvements, additions, and betterments, the cost of which is not deducted as an expense in the taxpayer's return, and from it should be deducted from time to time the amount of any definite loss or damage sustained by the property through casualty, as distinguished from the gradual exhaustion of its utility which is the basis of the depreciation allowance. In the case of the acquisition after March 1, 1913, of a combination of depreciable and non-depreciable property for a limip price, as, for example, land and buildings, the capital sum to be replaced is limited to that part of the lump price which represents the value of the depreciable property at the time of such acquisition, such value to be ascertained, if necessary, by estmiate. Method of Computing Depreciation Allowances. Regulations 45, article 166. — The capital sum to be replaced should be charged off over the useful life of the property either in equal annual installments or in accordance with any other recog- nized trade practice, such as an apportionment of the capital sum over units of production. Whatever plan or method of apportion- ment is adopted must be reasonable and should be described in the return. Modification of Method of Computing Depreciation. Regulations 45, article 167. — If it develops that the useful life of the property has been underestimated, the plan of computing depreciation should be modified and the balance of the cost of the property, or its fair market value as of March 1, 1913, not already provided for through a depreciation reserve, should be spread over the estimated remaining life of the property. 16 MANUAL FOR THE OIL AND GAS INDUSTRY A taxpayer who in computing depreciation allowance in returns for years prior to 1918 has not taken ordinary obsolescence into consideration may for the year 1918, and subsequent years, revise the estimate of the useful life of any property so as to allow for such future obsolescence as may be expected from experience to result from the normal progress of the art. No modification of the method should be made on account of changes in the market value of the property from time to time, such as, on the one hand, loss in rental value of buildings due to deterioration of the neighborhood, or, on the other hand, appreciation due to increased demand. The conditions affecting such market values should be taken into consideration only so far as they affect the estimate of the useful life of the property. Charging Off Depreciation. Regulations 45, article 170. — A depreciation allowance, in order to constitute an allowable deduction from gross income, must be charged off. The particular manner in which it shall be charged off is not material, except that the amount measuring a reasonable allowance for depreciation must be deducted directly from the book value of the assets or, preferably, credited to a depreciation reserve account, which must be reflected in the annual balance sheet. The allowances should be computed and charged off with express reference to specific items, units, or groups of property, each item or unit being considered separately or specifically in- cluded in a group with others to which the same factors apply. The taxpayer should keep such records as to each item or unit of depreciable property as will permit the ready verification of the factors used in computing the allowance for each year for each item, unit, or group. Closing Depreciation Account as to Any Item. Regulations 45, article 171. — If the use of the property in the business is permanently discontinued, although no sale or other disposition of the property has been made, a determination of any gain or loss may be made ; but any deduction in respect of any loss thereon must be disclosed in the taxpayer's return for the year in which the determination is made, and a full statement of the facts and the basis upon which the computation is calculated, must be MANUAL FOR THE OIL AND GAS INDUSTRY 17 attached to the return. Upon a sale or other disposition of the property, the consideration received shall be compared with the amount of the estimated salvage value used in computing the gain or loss as above provided, and the amount of the difference shall be treated as a gain or loss, as the case may be, of the year in which the sale or other disposition was made. Depreciation of Improvements in the Case of Oil and Gas Wells. Regulations 45, article 225. — Both owners and lessees operating oil and gas properties will, in addition to and apart from the deduction allowable for the depletion and return of capital as provided, be permitted to deduct a reasonable allowance for depreciation of physical property, such as machinery, tools, equip- ment, pipes, etc., so far as not in conflict with the option exercised by the taxpayer under article 223. The amount deductible on this account shall be such an amount based upon its capitalized value or cost equitably distributed over its useful life as will bring such property to its true salvage value when no longer useful for the purpose for which such property was acquired. Accordingly, where it can be shown to the satisfaction of the Commissioner that the reasonable expectation of the economic life of the oil or gas deposit with which the property is connected is shorter than the normal useful life of the physical property, the amount annually deductible for depreciation may for such property be based upon the length of life of the deposit. See article 161 et seq. Depletion and Depreciation of Oil and Gas Wells in Years before 1916. Regulations 45, article 226. — If upon examination it is found that in respect of the entire drilling cost of the wells, including physical property and incidental expenses, between March 1, 1913, and December 31, 1915, a taxpayer has been allowed a reasonable deduction sufficient to provide for the elements of exhaustion, wear and tear, and depiction, it will not be necessary to reopen the returns for years prior to 191G in order to show separately in these years the portions of such deduction representing depletion and depreciation, respectively. Such separation will be required to be made of the reserves for depreciation at January 1, 1916, and 18 MANUAL FOR THE OIL AND GAS INDUSTRY proper allocation between depreciation and depletion must be maintained after that date. In any case in which it is found that the deductions taken between March 1, 1913, and December 31j 1915, are not reasonable, amended returns may be required for these years. See Part II. In general, taxpayers claiming depreciation deductions will be required to submit the information called for in Schedule V, page 62. AMORTIZATION. The Revenue Act of 1918, section 214 (a) states that in com- puting net income there shall be allowed as a deduction : (9) In the case of builidngs, machinery, equipment and other facihtics constructed, erected, installed, or acquired on or after April 6, 1917, for the production of articles contributing to the prosecution of the present war, and in the case of vessels constructed or acquired on or after such date for the transportation of articles or men contributing to the prosecution of the present war, there shall be allowed a reasonable deduction for the amortiza- tion of such part of the cost of such facilities or vessels as has been borne by the taxjiayer, but not again including any amount otherwise allowed under this title or previous acts of Congress as a deduction in computing net income. At any time within three years after the termination of the present war the Commissioner may, and at the request of the taxpayer shall, reexamine the return, and if he then finds as a result of an appraisal or from other evidence that the deduction originally allowed was incorrect the taxes imposed by this title and by Title III for the year or years affected shall be redetermined, and the amount of tax due upon such redetermination, if any, shall be paid upon notice and demand by the collector, or the amount of tax overpaid, if any, shall be credited or refunded to the taxpayer, in accordance with the provisions of section 252. To determine the deduction allowable under tliis provision see Regulations 45, Revised, arts. 181-188. DEPLETION OF OIL AND GAS WELLS. Depletion may be defined as the loss sustained through the pro- gressive exhaustion of a mineral deposit. Depletion allowances are made in recognition of the fact that oil and gas deposits are exhaustible and that each unit of oil and gas removed reduces the amount recoverable, and hence reduces the value of the property. Act of 1918, section 214 (a), states: That in computing net income there shall be allowed as deductions : MANUAL FOR THE OIL AND GAS INDUSTRY 19 (10) In the case of mines, oil and gas wells, other natural deposits, and timber, a reasonable allowance for depletion and for depreciation of improve- ments, according to the peculiar conditions of each case, based upon cost, including cost of development not otherwise deducted: Provided, That in the case of such properties acquired prior to March 1, 1913, the fair market value of the property (or the taxpayer's interest therein) on that date shall be taken in lieu of cost up to that date: Provided further, That in the case of mines, oU 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 materiallj' disproportionate to the cost of the depletion allowance shall be based upon the fair market value of the property at the date of the discovery, or within 30 days thereafter; such reasonable allowance in all the above cases to be made under rules and regulations to be prescribed by the commissioner, with the approval of the Secretary. In the case of leases the deductions allowed by this paragraph shall be equitably apportioned between the lessor and lessee. . . . A reasonable deduction for depletion of natural deposits and for depreciation of improvevients is permitted, based — (a) Upon cost, if acquired after February 28, 1913 ; or (6) Upon the fair market value as of March 1, 1913, if acquired prior thereto; or (c) Upon the fair market value within 30 days of discovery in the case of mines, oil and gas wells, discovered by the taxpaj^er after February 28, 1913, where the fair market value is dispro- portionate to the cost. The essence of this provision is that the owner of such property, whether it be leasehold or freehold, shall secure through an aggre- gate of annual depletion and depreciation deductions the amount indicated in (a), (6), or (c), whicheve ■ applies to his particular case, plus in any case the subsequent cost of plant and equipment (less salvage value) and underground and overground develop- ment, which is not chargeable to current operating expense, but not including land values for purposes other than the extraction of minerals. Operating owners, lessors, and lessees are entitled^ to deduct an allowance for depletion, but a stockholder in a mining or oil or gas corporation is not. It should be noted thai in this and following paragraphs the privilege of revaluation within 30 days of discovery applies to the dis- coverer solely. No revaluation after March 1, 1913, is allowed where the value of property is enhanced by discovery made by any other than the taxpayer. 20 MANUAL FOR THE OIL AND GAS INDUSTRY ys Capital Recoverable through Depletion Allowance in Case of an Owner. In the case of operating owner in fee or lessor the capital recoverable through depletion allowances consists in — (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 (6) Cost of subsequent unprovements 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 which 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 gas. Depletion may be claimed against that portion of the cost or value which resides in the mineral deposit which is being exploited. To ob- tain this it is necessary to deduct from total cost or value the cost or value of the property 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 under (6), 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 depletion include items against which depreciation is l)cing charged ; that is, the cost (or value) of physical property may not be in- cluded, since it is returnable through depreciation deductions. Capital Recoverable through Depletion Allowances in 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 MANUAL FOR THE OIL AND GAS INDUSTRY 21 March 1, 1913, or its fair market value within 30 days after dis- covery; phis (6) 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. 9.) Any annual or period cal 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 acquisitioji may be charged to cost of leasehold until the property reaches the operat- ing 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. Under the Act of 1913, the lessee was not allowed a revaluation for purposes of computing his depletion deduction from gross in- come. And the depletion taken could not exceed 5 per cent of the value of the oil at the well. ' , or 10 cents, represents the unit cost of each barrel 2,000,000' of oil in the property at that date. He extracts and sells — 200,000 barrels in 1913 for $100,000 150,000 barrels in 1914 for 90,000 125,000 barrels in 1915 for 60,000 100,000 barrels in 191C) for 50,000 75,000 barrels in 1917 fur • 100,000 He has sold 050,000 barrels for $100,000 Deplotinn Doplction SustaiiuHl. Allowod. 1913 $20,000 $5,000 1914^ ' ' ' ' " 15,000 4,500 1915 12,500 3,000 1916. ' ' 10,000 10,000 1917^^^ 7,500 7,.500 Total ■ $65,000 $30,000 22 MANUAL FOR THE OIL AND GAS INDUSTRY For purposes of taxation in 1918 A's invested capital is $200,- 000- 65,000 = $135,000 and not $200,000 -30,000 = $170,000. The Revenue Act of 1918 allows A to revalue his property as of March 1, 1913. The valuation ("Capital Sum") claimed by A and allowed by the Commissioner was $1,000,000. The unit cost for purposes of computing depletion deductions , . $1,000,000 ^„ _„ , , from capital assets is ' ' , or $0.50 per barrel. Zi J UUU J \j\J\J The total depletion of capital sum to January 1, 1918, was, therefore, 650,000 X $0.50 = $325,000. Capital sum at January 1, 1918, is, therefore, $1,000,000 — $325,000, or $675,000, and not $1,000,000 -$30,000, or $970,000. A pportionment of Deductions between Lessor and Lessee. Regulations 45, article 204. — As the value of the property com- prehends the interests of both lessor and lessee, no computation for the purpose of depletion allowances, of the value of these interests separately as of any date which combined exceeds the value of the property in fee simple will be permitted. The same principle apples to holders of fractional interests. If the agree- gate 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 value of the property at a specified date determined in the manner explained in Regulations 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 only, or (h) a leasehold, or (c) a property subject to a lease, there shall be attached a statement setting forth the name and address and the precise 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 owner, except that ordinarily the only amount of capital to be returned is the cost of the oil or gas deposit if acquired subsequent to March 1, 1913, or its fair market value en bloc as of March 1, 1913, if acquired prior thereto, or within 30 days of discovery of oil or gas wells if discovered by the taxpayer. MANUAL FOR THE OIL AND GAS INDUSTRY 23 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 re- moved from the lessor's property by the lessee, irrespective of the amount of oil received by the lessor as royalty. However, in cases where the property was leased before JMarch 1, 1913, at a fixed price 'per unit, instead of a royalty payable in kind the lessor would be restricted 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 COSTS 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 lease- hold was acquired, the owner or lessee will be required upon request of the Commissioner 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 owner, in fact as well as in form, 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 deduc- tion, and in determining whether or not the price or cost at which any purchase or sale was made represented the actual market value of the property sold, due weight will be given to the relation- ship or connection existing between the person seUing the property and the buyer thereof. In general, the taxpayer will be required to submit the informa- tion called for in Schedule I, page 47. DETERMINATION OF FAIR MARKET VALUE. Introductory Statement. A determination of the fair market value of an oil or gas prop- erty (or the taxpayer's interest therein) is required : (a) In connection with the computation of dei)letion allow- ances : 24 MANUAL FOR THE OIL AND GAS INDUSTRY (1) As of March 1, 1913, in the case of properties acquired prior to that date; and (2) At the date of discovery or within 30 days thm'eafter 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. (6) In connection with computing the amount which may be included in paid-in surplus, as of date of conveyance, where the tan- gible property has been conveyed to a corporation by gift 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 capita^, assets in the case of properties acquired prior to March 1, 1913. Regulations 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 determined, subject to approval or revision by the Commis- sioner, by the owner of the property in the light of the conditions and circumstances known at that date, regardless of later dis- coveries or developments in the property or in methods of mining or extraction. The value sought should be that established assuming a transfer between a wilhng seller and a willing buyer as of that particular date. No rule or method of determining the fair market value of mineral 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, (6) 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, (/) valuation for local or State taxation, (g) partnership accountings, (h) records of litigation in which the value of the property was in question, (z) the amount at which the property may have been inventoried in probate court, (j) disinterested appraisal by approved methods, and (k) other factors. MANUAL FOR THE OIL AND GAS INDUSTRY 25 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 Dis- covery, page 45. Ruling Regarding Valuation. Valuation of fee under lease. — The valuation of a fee owner- ship 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 remain- ing to the owner of the fee title after deducting the value of the lessee's rights. But subsequent investments or discoveries by the lessee will not affect the lessor's valuation. No Revaluation of Property Permitted. Regulations 45, article 207. — The cost of the property or its fair market value at a specified date, as the case jnay be, plus subsequent charges to capital sum not deductible as current ex- penses, will be the basis for determining the depletion and depre- ciation deductions for each year during the continuance of the ownership under which the fair market value or cost was fixed, and durng such ownership there can be no revaluation for the purpose of this deductoin. This rule will not forbid the redis- tribution of the capital sum over the estimated number of units remaining in the property in accordance with either of the next two articles. Determination of Quantity 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 daj^s after the date of discovery, as the case may be. The oil reserves must })e esthnated for all untlc- veloped proven land as well as producing land. If information subsequently obtained clearly shows the estimate to have been materially erroneous, it may be revised with the approval of the Connnissioner, 26 MANUAL FOR THE OIL AND GAS INDUSTRY 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 determine 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 analysis of a great volume of production records ha? led to the development of the methods auggested in Part III of the Manual. Methods of 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 inserted as a suggestion. The underlying principle of the methods outlined i^ that the best indication of the future production of any well ts to be found in the history of similar wells in the same or similar districts, and that, other things being equal, a well's production is more likely to ap- proxima'e the production of a similar well in the tract or district than to deviate widely from the average. The method may be sunmiarized as follows: 1. Plotting the record of production of individual wells, or, lacking such detailed information, the average production per well for each tract. 2. Deriving from these graphical records an average or com- posite production decline 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 curve 4. Ascertaining probable total future production of producing wells by multiplying 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 of oil from the pool. It is to be emphasized that the value of estimates will depend aimost entirely upon the skill with which the method is carried MANUAL FOR THE OIL AND GAS INDUSTRY 27 out and the character of the production records upon which they are based. Where accurate detailed records are not kept, it ma}^ be difficult to determine a "reasonable allowance for depletion." The taxpayer may estimate his recoverable reserves by any method that can be shown to be well founded, but in all cases the data upon which such estimate was based must be submitted with a description of the method employed, and a resume of the cal- culations. 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 amount by the latter figure will give the unit value for the purpos^esj)f 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 original cost or value of the property, or circumstances make advisable a revised estimate of the number of mineral units in the ground, a new unit value for purposes of depletion may 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 number of units in the ground at the date of original acquisition or valuation less the number extracted prior to the taxable year. If, however, 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 re- serves in the property at the end of the j^ear. Each barrel of oil or unit of gas extracted and marketed niust, before a profit can be realized, pay not only its proi)ortionate share of the operating expense and deductions for depreciation and obso- lescence of physical property, but also must pay its proportionate share of capital sum returnable through depletion allowances. (See above.) This proportionate share of capital suni retm-nable through 28 MANUAL FOR THE OIL AND GAS INDUSTRY depletion allowances, which each unit of oil or gas must pay, is unit cost. Unit cost is obtained by dividing the capital sum returnable through depletion bj^ the "estimated recoverable reserve" at the beginning of the taxable year. The depletion deduction is computed by multiplying the unit cost by the number of units produced during he taxable year. It is to be noted that the estimated recoverable reserves and the number of units produced are used in estimating the depletion deduction for both lessor and lessee. Since, however, they are applied to different capital amounts returnable through depletion deductions, the unit costs for lessee and lessor are not identical, and the deductions 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. 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 (exclu- sive of value of physical property) was $20,000 Development cost (exclusive of cost of physical property) not other- wise 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 * ' 100.000 Estimated oil at beginning of year " 500,000 $100 000 Therefore unit cost is -n^/r^TTTTK- or per barrel $0 20 500,000 ■ A's depletion allowance for the taxable year is, therefore $0.20 X 100,000, or $20,000 B, the owner in fee of the property, had invested $40,000 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, ^^^7^7,7^7;, or per barrel $0 03 500,000 And his depletion allowance for the same year $0 . 03 X 100,000, or . . $3,000 MANUAL FOR THE OIL AND GAS INDUSTRY 29 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 ?) investment in the deposit is $15,000 He receives as bonus 5,000 His net investment in the deposit is therefore $10,000 He sells a one half mterest m 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 should deduct this amount from gross income as a loss in computing his tax, COMPUTATIONS OF ALLOWANCE FOR DEPLETION OF GAS WELLS. Regulations 45, article 211.— The deductions allowed in com- puting income from natural-gas properties are in general similar to those allowed oil operators, but the method of computing the de- ductions and the various assets differ in certain particulars, the most notable of which are involved in the problems of estimating the probable reserves and computing the depletion. On account of the peculiar conditions surrounding the pro- duction of natural gas it is necessa y to compute the depletion allowance for gas properties by methods suitable to the particular cases. Usually the depletion shou'.d 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 additional evidence on depletion is to be had from such considerations as (a) details of production and performance records of well or property, (6) decline in open flow capacity, (c) comparison with the life histories of similar wells or properties, particularly those now exhausted, and (d) size of reservoir and pressure of gas. 30 MANUAL FOR THE OIL AND GAS INDUSTRY METHODS OF COMPUTING GAS DEPLETION. Details of production or the performance record of the well or property. — 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, which will be indicative 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. — Where data are available the decline in open-flow 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-flow capacity are not available. Nevertheless it is probable that 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 available the rate of depletion of a gas well or property may be approximated by comparison with a neighboring well or property that has reached a later stage in life. Particu- larly is this applicable in a district where many gas wells have be- come exhasuted. For example, in a region where wells produce from 8 to 12 years, or an average of 10 years, a 10 per cent deduc- tion will be a rough approximation of the rate of depletion. Size of reservoir and pressure of gas, or the pore-space method, — For some properties 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 pressure of the gas could be accurately ascertained. In computing the reserves of an individual property by this method the migratoiy character of gas must be considered and the production and behavior of adjacent properties MANUAL FOR THE OIL AND GAS INDUSTRY 31 taken into account. The factors that make the niethod difficult to apply are difficulty of accurately ascertaining the thickness of pay, limits of pool, percentage of pore space, the effect of encroach- ing water and oil, and the quantity of gas remaining when com- mercial 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 de- creasing supply of natural gas in the ground is commonly observ- able in the behavior of the wells and the provision that must be made for transporting 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 significant symptom of the approaching termi- nation of the life of the well. The clogging of gas wells by par- affin, 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 proper- ties, 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 nioment 32 MANUAL FOR THE OIL AND GAS INDUSTRY 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 quantity of gas under- ground commonly varies with the decline in pressure and the relative quantity at the beginning and end of the tax year and at the time of abandonment, is, in the lack of better information, usable for tax purposes. Corrections and refinements of closed-pressure me.hod. — Several corrections and more or less important refinements are made in applying this method to the computation of depletion, and it should be borne in mind that it does not afford 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 reservoir 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 be- comes smaller as the gas is drawn and water or oil advances into a part of the space formerly occupied by the gas. The pressure is thus prevented from declining at a rate proportionate to the amount of gas 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 extent of the encroachment. How- ever, in a good many pools, after a study of the distribution of wells that have been "drowned out" and the history of water troubles in similar near-by pools, it is possible to make allow- ance 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 depletion is not precisely represented by the gauge readings, MANUAL FOR THE OIL AND GAS INDUSTRY 33 though the errors are generally so small that they may be ignored. For example, where the pressure declines from 1,000 to 500 pounds, the gas is not exactly half gone, for the reason the pressures referred to are guage readings and to each should be added the pressure of the atmosphere — for most fields about 14.4 points to the square inch. The fraction remaining in the ground then becomes ioT4.4- Account should also be taken of the pressure at which wells are abandoned in the 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 joio but gyf. The difference in the fraction where pressures of several hundred pounds are involved is not great and scarcely worth considering in view of the other errors wliich are certain to affect the result. However, after the pressure has declined to a low figure, the matter of correcting the fraction becomes of considerable importance. Thus, if the pressure of abandonment is 4 pounds guage 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-half of the recover- able gas has been withdrawn. Still another refinement that has, as a rule, more theoretical than practical value may be worthy of consideration in certain instances. This arises out of the fact the gases do not expand precisely as the pressure decreases, and that even i' the size of the natural reservoir remains fixed the pressure does not decline in exact proportion to the amount of gas removed. The difference amounts to only a few per cent and is greatest for liigh 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 Boyle's law, and in a decline from 1,500 pounds to 1,000 pounds the departure is still greater. The correction varies from 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 differences 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 34 MANUAL FOR THE OIL AND GAS INDUSTRY per square inch. Also the expense of marketing gas after the pressure has become low is greater than when it was high, largely because of the necessity of installing compressors to push the gas through the pipe lines to the consumers. These two considera- tions have a tendency to balance each other and, with certain ex- ceptions, 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 attach- ing 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. Ordinarily, 24 hours will be suffi- cient for this purpose, but for some wells several days or even a longer period will be required, owing to the slowness of equalization of pressure in the sand. APPORTIONMENT OF DEPLETION AMONG VARIOUS SANDS. Where more than one sand under a property is yielding gas, the problem arises as to how to weight or evaluate the decline in pressure 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 weight- ing of the pressure declines, or if facts indirectly indicating ca- MANUAL FOR THE OIL AND GAS INDUSTRY 35 pacity 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. SEASON FOR TESTING WELLS FOR CLOSED PRESSURE. For many fields summer or early fall readings furnish the best indication of decline in closed pressure. It is therefore recom- mended that such readings be taken regularly and consistently. Summer or fall readings are of especial value because these seasons for mofet fields are at the end of a period during which the wells have not been sub'ect to heavy draft, and hence are in best con- dition to accurately reflect the pressure of the gas in the under- ground pool or reservoir. If pressures of all wells or representative wells are observed 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 pres- sures observed at other times. Obviously, 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 taxable year the pressure declines to 700 pounds, the rough infer- ence may be drawn that three-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 w^ell is completed on another part of the tract and that its initial pressure is 800 pounds. If by the end of the year the pressure of this well has declined to 700 pounds while the pressure of the first well has dropped to 500 pounds, the fraction of the capital account return- able through depiction the second year, is proportional to the average decline in pressure, assuming that there are no water troubles or other noteworthy complications. The average of 700 and 800 is 750 and the average of 500 and 700 is 600. The differ- ence 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 36 MANUAL FOR THE OIL AND GAS INDUSTRY computation and it is treated as though it were finished at the beginning of the year. The rate of decHne within the year is of httle consequence, the main consideration being the amount of decKne for the whole year. If the year's dechne 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 pressure 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 new one at its completion averaged 600 pounds, and the average of the three at the end of the year was 300. The depletion indicated is 50 per cent of the remaining capital account. It is suggested that the capital sum at the beginning of each year be treated as 100 per cent for the average pressure at the beginning of the year, and the average decline during the year will then furnish a readily usuable basis for computing the depletion allowance. The amount of gas in the ground is, as a rule, to be regarded as 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: -Xz = depletion allowance. ' y 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 abandonnient; z is MANUAL FOR THE OIL AND GAS INDUSTRY 37 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 A^ear and sub- tracting the sum of the pressures at the end of the year. The formula may also be written as follows: Sum of pressures at beginning of C apital sum to end of tax year tax year + _ Depletion Sum of the pressures at begin- sum of pres- allowance, ning of year — sum of pressures sures of new at time of expected abandon- wells — sum ment. of pressures at end of tax year. 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 read- ings, 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, si- phoned, or pumped off before the well is closed. A closed-pressure reading of a gas well which has been produc- ing, 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 o- time it has been closed in. It is necessary to record the length of time the well has been closed and to show how the pressure built up during this period. Successive readings will indicate the point at which the pressure becomes approximately stationaiy ; that is, the point at which the closed pressure approaches as nearly as possible the maximum pressure which would be shown if all wells in the pool were closed for several months. The length of time required varies with the character of the sand, position of the packer, the location of the :^ 38 MANUAL FOR THE OIL AND GAS INDUSTRY well with reference to other wells, the limits of the pool, and other factors. The depth of the well, diameter of tubing, and line pressure when the well was shut off should be noted. Since readings at the exact end of the taxable year will ordi- arily not be available, the pressure of that date may be obtained by interpolation or extrapolation. In certain cases readings taken regularly in September or some other month may be applicable to the end of the taxable year. As a general rule September closed- pressure readings furnish the best indication of depletion, and it is recommended that such readings be made with regularity and care. Where interpolated or extrapolated readings are used, the data from which they are obtained should be given. Gauges should be of appropriate capacity and should be frequently tested. Record should be kept of the number of gauges, date each was tested, names of men testing, and other significant details. COMPUTATION OF COMPLETION ALLOWANCES WHERE QUANTITY OF OIL OR GAS IS UNCERTAIN. Regulations 45, article 213. — Computation of depletion allow- ance 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 determine with any degree of certainty the quantity of oil or gas in a property, it will be necessary to make a tentative estimate which will apply until production figures are available from which an accurate 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 which data are available, such as individual wells or tracts, and these, added together into a grand total, to be apphed to the total capital assets returnable 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 MANUAL FOR THE OIL AND GAS INDUSTRY 39 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 prop- erties will determine the amount which may be allowably deducted from the gross income of that year. In the case of sale of particular tracts, full account must be taken of the depletion of such tracts in computing profit or loss thereon. COMPUTATION OF DEPLETION ALLOWANCE FOR COMBINED HOLDINGS OF GAS PROPERTIES. Regulation 45, article 214 (2) . — In the 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 taxpayer's wells in each pool in the formula given in article 211. The total allowance for depletion of the gas properties of the taxpayer 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 tha the expense of making separate estimates for individual tracts may be greater than the benefits arising from such a procedure. DEPLETION AND DEPRECIATION ACCOUNTS OF BOOKS. Regulation 45, article 216. — Every taxpayer claiming and mak- ing a deduction for depiction and depreciation of mineral property shall keep accurate ledger accounts in which shall be charged the fair market value as of March 1, 1913, or within 30 days after the date of discovery, or the cost, as the case may be (a) of the prop- erty, and (6) of the plant and equipment, together with (c) such amounts expendcMl 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 bo ereclited with the amount of the depre- ciation and dei~)l('tion deductions claimed and allowed each year, or the aniounts of the depreciation and depiction shall be credited 40 MANUAL FOR THE OIL AND GAS INDUSTRY to depletion 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 return- able 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 physi- cal 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. A distribution made from such a reserve will be considered a liquidatmg dividend and will constitute taxable income to a stock- holder 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 surplus and undivided profits of the corporation. In general, any distribution made by a corporation other than out of earnings or profits accumulated since February 28, 1913, is to be regarded as a return to the stockholder of part of the capital represented 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. MANUAL FOR THE OIL AND GAS INDUSTRY 41 STATEMENT TO BE ATTACHED TO RETURN WHERE DEPLETION OF OIL OR GAS IS CLAIMED. Regtlations 45, article 218. — To each return made by a person owning 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 machinery, 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 sub- sequent to February 28, 1913, and not covered by the foregoing clause : (b) 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. 23) ; (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 case may be, by the estimated number of units of oil or gas, pounds per square inch in the case of gas) in the property 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 desir- able fhat this information be furnished by months) ; (g) The number of acres of producing and proven oil or gas land: (h) The number of wells producing at the beginning and end of the taxable year; (i) 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 42 MANUAL FOR THE OIL AND GAS INDUSTRY showiHg the location of the property and of the producing and abandoned wells, dry holes, and proven oil and gas land; (Z) The average gravity of the oil produced on the tract; (m) The nun.ber 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 have 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 information 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 cov- ered by the above statement the following information must be furnished.) Annual production of the tract or of the individual wells, if the latter 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 (r) Any other data which will be helpful in determining the reasonableness of the depletion deduction. Maps. Maps that accompany records and delineate property boun- daries must be sufficiently extended to show the position of prop- erty in relation to section, township, and range lines, or in areas of metes and bounds survey, the relation to two or more estab- lished lines, of either township or district. On some part of the map should be recorded the name of the State, county, township, or district, name of the company or individual representing 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 de- partment 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 char- acter of each well should be indicated by appropriate symbols. MANUAL FOR THE OIL AND GAS INDUSTRY 43 Where wells have been drilled by another company or indi- vidual it is advisable to distinguish such wells by some ifj'mbol or abbreviation, explaining the symbol in a marginal note. When a taxpayer has filed adequate maps with the Commis- sioner he may be relieved of filing further maps of the same properties, provided all additional information necessary for keep- ing 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 belonging 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 frozn each tract should be given for each year. REVALUATION OF OIL OR GAS PROPERTIES DISCO^/ERED SINCE MARCH 1, 1913. Section 214 (a) and 234 (a) of the Revenue Act of 1918, state — that in the case of mines, oil and gas wells, discovered by the taxpayer on or after March 1, 1913, and not acciuired as a result of purchase of a proven tract or lease, where the fair market value of the property is materially dispropor- tionate to the cost, the depletion allowance shall be based on the fair market value of the property at the date of the discovery or within 30 days there- after; 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 Regulations 45: Art. 220. Oil and gas wells. — Section 214 (a) (10) and section 234 (a) (9) provide that taxpayers who discover oil and gas wells on or after March 1, 1913, may, under the circumstances therein prescribed, determine the fai market value of such property at the date of discove y or within 30 days thereafter for the purpose of asceitaining allowable deductions for depletion. Before such valuation may be made the statute requires that two conditions precedent be satisfied, (1) that the fair market value of such property (oil and gas wells) on the date of discovery or within 30 44 MANUAL FOR THE OIL AND GAS INDUSTRY days thereafter became materially disproportionate to the cost, by virtue of the discovery, and (2) that such oil and gas wells were not acquired as the result of purchase of a proven tract or lease. Art. 220 (a). Discovery — Proven tract or lease — Property disproportionate value. — (1) For the purpose of these sections of the revenue act of 1918, an oil or gas well may be said to be dis- covered when there is either a natural exposure of oil or gas, or a drilling that discloses the actual and physical presence of oil or gas in quantities sufficient to justify commercial exploitation. Quantities sufficient to justify commercial exploitation are deemed to exist when the quantity and quality of the oil or gas so recovered from the well are such as to afford a reasonable expec- tation of at least returning the capital invested in such well through the sale of the oil or gas, or both, to be derived therefrom. (2) A proven tract or lease may be a part or the whole of a proven area. A proven area for the purposes of this statute shall be presumed to be that portion of the productive sand or zone or reservoir included in a square surface area of 160 acres having as its center the mouth of a well producing oil or gas in commercial quantities. In other words, a producing well shall be presumed to prove that portion of a given sand, zone, or reservoir which is included in an area of 160 acres of land, regardless of private boun- daries. The center of such square ai^a shall be the mouth of the well, and its sides shall be parallel to the section lines established by the United States system of public land surveys in the district in which it is located. Where a district is not covered by the United States land surveys, the sides of said area shall run north and south, east and west. So much of a taxpayer's tract or lease which lies within an area proven either by himself or by another is " proven tract or lease " as contemplated by the statute, and the discovery of a well thereon will not entitle such taxpayer to revalue such well for the purpose of depletion allowances, unless the tract or lease had been acquired before it became proven. And even though a well is brought in on a tract or lease not included in a proven area as heretofore defined, nevertheless it may not entitle the owner of the tract or lease in which such well is located to revaluation for depletion purposes, if such tract or lease lies within a compact area which is immediately surrounded by proven land, and the geologic MANUAL FOR THE OIL AND GAS INDUSTRY 45 structural conditions on or under the land so inclosed may reason- ably warrant the belief that the oil or gas of the proven areas extends thereunder. Under such circumstances the entire area is to be regarded as proven land. (3) The " property " wliich may be valued after discovery is the " well." For the purposes of these sections the " well " is the drill hole, the surface necessary for the drilling and operation of the well, the oil or gas content of the particular sand, zone, or reservoir (limestone, breccia, crevice, etc.) in which the discovery was made by the drilling, and from which the production is drawn, to the limit of the taxpayer's private bounding lines, but not beyond the limits of the proven area as heretofore provided. (4) A taxpayer to be entitled to revalue his property after March 1, 1913, for the purpose of depletion allowances must make a discovery after said date and such discovery must result in the fair market value of the property becoming disproportionate to the cost. The fair market value of the property will be deemed to have become disproportionate to the cost when the output of such well of oil or gas affords a reasonable expectation of returning to the taxpayer an amount materially in excess of the cost of the land or lease if acquired since March 1, 1913, or its fair market value on March 1, 1913, if acquired prior thereto, plus the cost of exploration and development work to the time the well was brought in. Art. 221. Proof of discovery of 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: (a) A map of con- venient scale, showing the location of the tract and discovery well in question and of the nearest producing well, and the develop- ment for a radius of at least 3 miles from the tract in question, both on the 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 the location, the date drilling began, the date of com- pletion and beginning of production, the formations penetrated, the oil, gas, and water sands penetrated, the casing record, includ- ing the record of perforations, and any other information tending to show the concUtion of the well and the location of the sand or zone from which the oil or gas is prochiced on the date the discovery was claimed; (c) a sworn record of proihiction, clearly jiroving ihc 46 MANUAL FOR THE OIL AND GAS INDUSTRY commercial productivity of the discovery well; (d) a sworn copy of the records, showing the cost of the property; and (e) a full explanation of the method of determining the value on the date of discovery or within 30 days thereafter, supported by satisfactory evidence of the fairness of tliis value. CHARGES TO CAPITAL AND TO EXPENSE IN THE CASE OF OIL AIID GAS WELLS. Regulations 45, article 223. — Such incidental expenses as are paid for wages, fuel, repairs, hauling, etc., in connection with the exploration of property, drilling of wells, building pipe lines, and development 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 computed, 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 productive wells. The taxpayer should adopt a consistent poHcy as to capitalizing or charging off cost of drilhng non- productive 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 written 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 MANUAL FOR THE OIL AND GAS INDUSTRY 47 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). Where deductions for depreciation or depletion have either 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 where capital expendi- tures have been charged to expense in lieu of depreciation or depletion, a statement indicating the extent to which this prac- tice 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 forward 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 Revenue Act of 1918 the amount recoverable through depletion will be the cost, or the value as of March 1, 1913, or within 30 days of the date of discovery, as the case may be, less proper allowance for the mineral or other prop- erty removed prior to January 1, 1918. APPENDIX TO PART I. SCHEDULES. /. Schedule for Ascertaining Cost of Property as of any Specified Date. 1. Name of property. 2. Location of property. 3. Are you sole owner of property? 4. If not sole owner, your ownership interest therein. 5. Is property a leasehold? 6. (a) If so, name and address of lessor and lessee. (b) Date lease effective. (c) Date of expiration. (d) Royalty rate. (e) Bonus, either cash or property. 48 MANUAL FOR THE OIL AND GAS INDUSTRY 7. Date property was acquired. 8. (a) Manner of acquisition: (Purchase, trade, gift, etc) (6) 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 part}^ estab- lishing cash value of a resume of his report. (/) Cash value of total consideration paid for property as estabhshed by you. Map. 9. 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 1/3180 or 2 inches to the mile for developed areas, and should show the following information for each tract as of date of acqui- sition: (a) Wells producing. (6) Wells temporarily suspended. (c) Wells formerly productive but now abandoned. (d) Wells completed to oil or gas sand or zone but non-pro- ductive. (e) Wells abandoned before completion. (/) Wells drilling. (g) Area considered (1) producing, (2) proven, (3) highly probable, and (4) possible oil and /or gas lands, and (5) land worth- less for oil and /or gas production. (Proven or proved oil or gas MANUAL FOR THE OIL AND GAS INDUSTRY 49 land is 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.) In the case of a company owning more than one tract in a single pool or field, a field map folded to letter-size dimensions, say, 8 by 10 inches, if not too cumbersome, may be sent, and each tract designated by a letter or some other convenient symbol. Lajid Data. 10. Area in acres as of date of acquisition of — (a) Fully developed oil or gas territory. (6) Proven oil or gas territory. (c) Highly probable oil or gas territory. (d) Possible oil or gas territoiy. (e) Territory worthless for oil or gas production. (/) Total acreage. 11. Name and address of the party making land classification as covered in questions 9 and 10. Well Data. 12. Furnish the following information as of date of acquisition: (a) Number of wells producing. (b) Number of wells abandoned or temporarily suspended. (c) Nuniber of wells drilling. (d) Number of new locations yet remaining undrilled on proven territory. 13. (a) Number of producing oil and /or gas sands proven on property. (6) Designation of the different sands, with the average thickness of each and average depth from surface to the top of each sand. (c) Any other information regarding conditions in wells which might be used to classify the wells in groups. (d) List of wells as of date of acquisition, showing the fol- lowing information regarding each: (1) Number or letter by which each is designated. (2) Date of beginning drilling. (3) Date of beginning of production. 50 MANUAL FOR THE OIL AND GAS INDUSTRY (4) Date abandoned. (5) Initial daily production. 14. Subniit table showing — (a) Production of tract by calendar years from the begin- ning of production to date of acquisition, with average number of wells producing each yeai (6) The same information for calendar years subsequent to date of acquisi ion. (c) Amount received each year for production mentioned in (a) and (6). (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. (g) Total amount received for production mentioned in (e) and (/). (/i) 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. (h) Same information for period subsequent to date of acquisition, (c) If, through any cause, it is impossible to give yearly production records by individual wells, state the reasons why this information is not available. Oil and Gas Reserves in Property. 16. (a) What was the estimated total number of units of oil and/or gas in the property on date of acquisition? (6) How was this estimate made? ■ (c) Append a copy of the appraisal from which the esti- mates were derived or append a resume of the calculations utilized in making the estimate. (d) Give name and address of party making the estimate. 17. (a) State range in specific gravity of oil recovered. (b) State average specific gravity oil delivered. MANUAL For the oil and gas industry 51 (c) If more than one grade delivered, give percentage of each for a year of acquisition. Casing-head Gas. 18. Submit table Fhowing — (a) Quantity of casing-head gas produced by months from date of first production to date of acquisition. (6) Quantity of casing-head gas produced by months for period subsequent to date of acquisition. (c) Average number of wells contributing to this produc- tion each year, (d) In case the gas i> sold, give the amount received each month f o gas mentioned in (a) and (6) . (e) Quantity of gasoline in gallons recovered each year from casing-head gas, mentioned in (a) and (b). (/) Amount received each month for gasoline mentioned in (e). (g) Average price per gallon received for gasoline men- tioned in (e). (h) Production of oil by months for the wells from which this casing-head gas is taken. Give this informa- tion by individual wells if possible; if not, then by tracts with number of wells producing each month. When monthly records are not available give data by years. Gas-well Data 19. Submit table giving list of gas wells as of date of acquisition, and showing — (a) Number or letter by which each is designated. (6) Date of begimiing drilling, (c) Date of beginning production. {d) Date of abandonment. (e) Initial open flow capacity. (f) Initial closed rock pressure. {g) Closed rock pressure as of date of acquisition. 52 MANUAL FOR THE OIL AND GAS INDUSTRY Gas-production Data. 20. Submit table showing — (a) Gross production (of gas) by calendar years, from beginning of production to date of acquisition, with number of wells producing each year. (6) Same information for years subsequent to date of acquisition. (c) Amount of money and cash value of any other con- sideration received each year for production men- tioned in (a) and (6). (d) Average price per thousand cubic feet of gas, by years from beginning of production. (e) Total yield from beginning production to date of acqui- sition, 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. (o) Average rock pressure in September of each year during which production has been maintained. (6) Rock pressure of individual or test wells on tract. (Answers should be attached as a separate state- ment giving all rock pressures measured during life of the well or property. The method used in measuring pressures should be mentioned.) Physical Property. 23. Does the cost of property as given in 8 (/) of this schedule include 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? 24. If it does, what amount is applicable solely — (a) To the value of the oil and gas contents? (h) 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? MANUAL FOR THE OIL AND GAS INDUSTRY 53 25. Give general inventory as of date of acquisition of the physical property mentioned in 24 (c) with the following information regarding each type: (a) Year originally acquired. (&) Original cost. (c) Depreciation sustained to date of acquisition. (d) Estimated cost as of date of acquisition. II. Schedule for the Valuation of Property as of any Specified Date. Introduction. — In actually determining the fair market value of any 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 specified date as to which the valua- tion is set up and is not the date on which the appraisal is made. 1. Description of the property. (a) A legal description of the property, mcluding its loca- tion in section (or farm), township, range, county, and State. (h) Whether or not the taxpayer is the sole owner; and if not, his ownership interest therein and the names • and addresses and ownership interest of each of other joint owners. (c) Whether the property is a leasehold; if so, the name and address of the lessor and lessee. (d) The date lease was effective. (e) Date of expiration. (J) Royalty rate. (g) Bonds, either cash or property. (h) 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 tlio pr()i)erty, whether l)y purchase, trade, gift, etc. 54 MANUAL FOR THE OIL AND GAS INDUSTRY (6) 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. Land data. — A statement as to the number of acres con- sidered fully developed, proven, highly probable, pos- sible, 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 producing, abandoned, or suspended, drilling and the number of locations remaining undrilled on proven terri- tory. (b) The number and designation of the oil or gas sands proven on the property, with their average thick- ness and the average depth from the surface of the top of each sand. 7. Individual well data. — The following information regarding the individual wells: (a) The number of the well. (6) Date began drilling. (c) 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 appraisal. MANUAL FOR THE OIL AND GAS INDUSTRY 55 (6) 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. (e) The total production prior to and subsequent to date of appraisal. (/) The total amount received prior to and subsequent to the date of valuation. Where production figures of individual wells are avail- able, give the records for all years from the begin- ning 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. 9. 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 operators are prone to say it is impossible to esti- mate the quantity of oil or gas under any tract — obviously it is impossible to determine this exactly but it can be done with reasonable accuracy in most instances.) (&) How this estimate was made. (c) The name and address of the party making the estimate and a copy or resume of his report. 10. Specific gravity. (a) The range in specific gravity of the oil recovered. (6) The average specific gravity of the oil delivered, 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 followmg information by months: (a) The quantity, in thousands of cubic feet, produced prior to and subsequent to the date of appraisal. (6) The number of wells producing this gas. (c) The amount received for the gas, if such was sold direct. {d) The quantity, in gallons, of gasoline made. (e) The amount received for this gasoline. (/) The average price per gallon. 66 MANUAL FOR THE OIL AND GAS INDUSTRY (g) The production of oil by months for the wells yielding the gas covered by this paragraph. 12. Gas properties. — In the case of gas properties the well data should include: (a) The number of each well. (h) Date began drilhng. (c) Date began producing. (d) Date abandoned. (e) Initial daily capacity. (J) 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, (a) Number of wells producing. (6) 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 pres- sure 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 MANUAL FOR THE OIL AND GAS INDUSTRY 57 regarding any bona fide transactions in oil or gas prop- erties in the region of the tract under appraisal about which the taxpayer is able to obtain data, this informa- tion to include as rnany of the items called for in con- nection 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 ap- praisal. (6) 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 fol- lowing 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 portion 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 property? (e) What portion represents personal property. (/) What portion of the assessed value of the real property represents oil or gas in the ground? 17. If the values are established by any other method than the above a full description of the method used and con- clusions reached should be given. 18. If the valuation of the property includes any amount 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 should be segregated under the headings: (a) Value of oil and gas contents. (6) 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 appraisal should be given, together with the following information regarding each type of property: (o) When the equipment was first used. 58 MANUAL FOR THE OIL AND GAS INDUSTRY (6) 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 subse- quent to the date of appraisal. The classification of physical equipnient will be found under the chapter on depreciation, page 78 of this Manual. Indirect Methods of Determining Value. 20. The book value of the total assets on the date of valuation exclusive 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. (6) Whether or not these outstanding shares were fully paid. (c) 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 appraisal. 22. Total permanent indebtedness classified as bonds, notes, contracts, etc., and what the quoted value of these securities was or any particulars regarding public or private transactions which would tend to estab- lish their value. 23. 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 of 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 MANUAL FOR THE OIL AND GAS INDUSTRY 59 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 region of the property, or of any interest or stock therein has been involved in any partnership account- ing known, a statement regarding such accounting should be given. 27. If anyone interested in the oil and/or gas wells in the par- ticular region of the property under discussion or as owner, operator, or member of a partnership, or stock- holder in a corporation owning 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 loca- tion 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 sub- mit any other evidence, facts, statements, etc., which he desires to have considered in the determination of the value as of the date of appraisal. ///. Schedule for Proof of Discovery Introduction. — In order to prove to the satisfaction of the Com- missioner that a bona fide discovery of oil or gas in commercial quantities 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 loca- tion in section (or farm), township, range, county, and State. (6) Whether or not the taxpayer is the sole owner, and if not, his ownership interest therein, and the names and addresses and ownership 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 lessee. (d) The date lease was effective. (e) Date of expiration. (/) Royalty rate. 60 MANUAL FOR THE OIL AND GAS INDUSTRY (g) Bonus, either cash or property. (h) 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; (6) The producing, suspended or abandoned and drilling wells; and (c) The areas which are considered producing, p:oven, highly probable, possible, or worthless oil or gas land. 5. A certified copy of the log of the discovery well, showing: (a) The location. (b) Date drilling began, date of completion and the begin- ning of production. (c) The formations penetrated; the oil, gas, and water sands penetrated; the casing record, including the record of perforation and any other informa- tion tending to show the condition of the well and the location of the sand of sands from wliich 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 the completion of the discovery in the vicinity of the discovery well to convince the Comniissioner 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 producing wells, the production data from enough MANUAL FOR THE OIL AND GAS INDUSTRY 61 wells within this area to indicate the average produc- tivity of the wells drilled prior to the date of drilhng the discovery well : 9. The specific gravity of: (a) The oil recovered from the discovery well. (6) 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 disco veiy : (a) Number of well. (6) Date of beginning drilling. (c) Date of beginning production. (d) Date abandoned. (e) 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 formation penetrated. (g) The casing record and any other information tending to show the condition of the well on the date dis- covery 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 for Depletion. With respect to each property producing oil and/or gas during the taxable year for which the return under consideration was filed give the following facts : 1. Description of property. 2. Value (exclusive of physical properties) as of March 1, 1913, or 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: 62 MANUAL FOR THE OIL AND GAS INDUSTRY (a) Capital sum returnable through depletion at begin- ning of year. (b) Capital returnable through depletion added during year. (c) Total capital sum against which depletion for year is chargeable ((a) plus (6)). (d) Estimated quantity of recoverable crude oil in ground at beginning of year, in barrels of 42 gallons. (e) Production for year in barrels of 42 gallons. (/) Unit cost of recoverable product ((c) divided by (d)). (g) Amount of depletion sustained during year ((/) mul- tiplied by (e)). V. Schedule for Depreciation. With respect to each tract on which there is physical property mentioned 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 begin- ning of year. (6) Capital returnable through depreciation added during year. (c) Total capital sum against which depreciation for year is chargeable (a) plus (b). (d) Amount of depreciation sustained during year. VI. Schedule for the Proof of Bona Fide Sale. Introduction. — To prove that the sale consummated by the taxpayer is actually bona fide, he will be required to furnish a sworn statement, including the following: 1. Description of the property. (a) A legal description of the property, including its loca- tion in section (or farni), township, range, county, and State. (6) Whether or not the taxpayer is the sole owner, and if MANUAL FOR THE OIL AND GAS INDUSTRY 63 not, his ownership interest therein, and the names and addresses and ownership 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. (h) 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 considerations. (6) The par value of the stock, bonds, or other con- siderations. Note. — If the "unit-cost" method of computing depletion was not used in computing the depletion allowance for the various years mentioned in the above table, state what method was used in calculating the depletion, and give a complete resume of the calculations, 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. (c) The actual cash value of the stock, bonds, or other considerations on the date of disposal of the property. (d) How these cash values were established. (e) The name and address of the party determining or establisliing these values. 5. Total cash value of all considerations received by the tax- payer for the property. 6. (a) The name and address of the party to whom the prop- erty was transferred. (b) The connection, business or other, if any, between parties to the transfer. 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 64 MANUAL FOR THE OIL AND GAS INDUSTRY 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 estab- lished for this schedule. 8. Any evidence, facts, statements, etc., which the taxpayer desires to have considered as a proof in the determina- tion of the bona fide character of the transaction. VII. Schedule for Computation of Profits 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 property. 3. Manner of disposal of the property (sale, trade, gift, etc.). 4. Amount received in cash. 5. Amount received in stock: (a) Par value of stock. (6) Actual cash value of stock. (c) How was this cash value established? 6. Amount received in bonds: (a) Par value of bonds. (6) Actual cash value of bonds. (c) How was this cash value established? 7. Amount received in other considrations : (a) What were these considerations? (6) Actual cash value of these considerations. (c) Manner of determining this cash value. (d) Name and address of the party determining this value. 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 deple- tion added subsequent to March 1, 1913, or subse- quent to date of acquisition if property acquired sub- quent to March 1, 1913. 11. Total of all additions to capital returnable through depre- ciation added subsequent to March 1, 1913, or subse- MANUAL FOR THE OIL AND GAS INDUSTRY 65 quent to date of acquisition if acquired subsequent to March 1, 1913. 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 of 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 (dif- ference between 8 and 15). VIII. Schedule for Proving that the Principal Value has been Denioristrated hy Prospecting or Exploration and Discovery Work Done hy the Taxpayer. Introduction. — In the case of a bona fide sale of oil or gas prop- erties it will be necessary, in order to secure the benefits of sections 211b and 337 of the Revenue Act of 1918, which limits the portion of the surtax imposed by said act attril^utable 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 fol- lowing among other data: 1. Description of the property. — (a) A legal description of the property, including its loca- tion in section (or farm), township, range, county, and State. (6) Whether or not the taxpayer is the sole owner, and if not, his ownership interest therein, and the names and addresses and ownership interest of each of other joint owners. (c) Whether the property is a leasehold; if so, the name and address of the lessor and lessee. (d) The date lease was effective. (e) Date of expiration. (/) Royalty rate. 66 MANUAL FOR THE OIL AND GAS INDUSTRY (g) Bonus, either cash or property. (h) Any unusual terms of lease. 2. The value of the property immediately prior to the date of beginning the prospecting or exploration and discove y work done by the taxpayer leading to the discovery claimed. — (Tliis may be established through filling out Schedule II as of the specified date.) 3. The proof that a discovery has been made. — (To furnish this proof the taxpayer will be required to fill out Schedule III.) 4. The value of the proverty at any specified data within a rea- sonable time after the discovery was made. — (This value may be estabhshed by filling out Schedule II for the specified data.) 5. Any evidence, facts, statements, etc., which the taxpayer desires to have considered as showing that the prin- cipal value of the property has been demonstrated by prospecting or exploration and discovery 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 con- clusions of a committee appointed to investigate and standardize depreciation allowances in the case of oil and gas properties. It is prepared 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 5 ' companies and individuals were canvassed in this work and th? conclusions were reached by considering the company practices as well as taking into account the experience of the members of the committee and the precedents and practices of the Treasury Department. The percentages and tables included in this paper are intended as a suggestion for the guidance of the taxpayer in calculating his just tax. The percentages are neither maximum nor minimum rates. They are not to he applied indiscriminately to specific prop- erty, and the Internal Revenue Bureau is in no way committed to accept allowances based upon them. Every claim for deduction must be accompanied by a detailed statement of the facts upon which such claim is based. Each class of equipment 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 percentages to conform to the depreciation as it actually occurs. It must be borne in mind that it is not possible to make stand- ard rules or formula to cover all conditions in this business. Although different rates may reasonably be applied in different 67 68 MANUAL FOR THE OIL AND GAS INDUSTRY parts 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 practically negligible in most instances. Whenever the life of the property is materially shorter than that called for in this schedule, a special rate may be claimed, or the difference may be made up by replacements charge- able 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. 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 premature 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 equip- ment as a whole, depreciated at the following rate Per Cent. First year 40 Second year 25 Third year 15 Fourth 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 equip- MANUAL FOR THE OIL AND GAS INDUSTRY 69 merit 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 depre- ciation rate of the physical equipment will be governed by the reasonable expectation 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 appraisement of the Independent 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: Depreciation per Year. Electric Pipe . . . Tank . . Per Cent. 20 50 50 CLASS A, NO. 4.— TANKS. The following depreciation rate for tanks is recommended : Per Cent. Steel, 5,000 to 55,000 barrels Steel, 2,500 to 5,000 barrels G. I., 500 to 2,500 barrels G. I., less than 500 barrels Wood Movable tanks: G. I., 500 to 2,500 barrels G. I., less than 500 barrels G. L, water tanks, 500 to 2,.')()0 barrels. G. I., water tanks, less than 500 barrels 12^ 20 lU 16| 12J 20 70 MANUAL FOR THE OIL AND GAS INDUSTRY These results may be used for all classes of service — that is, oil producing, refineries, etc. CLASS A, NO. 5.— TOOLS. 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 equip- ment an average life of three years is recommended, using an annual depreciation of 33^ per cent. CLASS A, NO. 6.— TRANSPORTATION 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 33| per cent. In fact, the average life of automobiles is less than three years. The 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 approximately 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. As oil-well niotors 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. MANUAL FOR THE OIL AND GAS INDUSTRY 71 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 depre- ciation rate of 14t 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 expensive 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 founda- tion with siding and shingle or patent roof-painted, have an aver- age 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 16f 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, l)oilers, etc.), auxili- ary equipment, buildings, telephone and telegraph, and tenninal facilities. It is recommended that — Mains 6 inches in diameter or over be based on a 20-5^ear life or an annual depreciation of 5 per cent. Mains under 6 inches diameter be based on a IG-ycai life or an annual depreciation of 61 per cent. Gathering lines be based on a 10-year life or an animal depre- ciation of 10 per cent, with a salvage of 10 per cent. 72 MANUAL FOR THE OIL AND GAS INDUSTRY Pump stations, including all equipment, telephone lines, and terminal facilities a life of 10 years, or an annual depreciation of 10 per cent. These conclusions were reached after carefully considering detailed 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 com- parison with the amounts invested, so far as making any special allowances in depreciation. 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 Steel storage Buildings Total Machinery: Pumps Boiler Heaters Miscellaneous (freight, etc.) Total Wirirg Fittings Commissary Telephone lines Spurs, loading racks, etc Sundries (tools, paints, water wells, etc., superin- tendence supervision) Total Grand total cost $83,176 497,358 1,323,901 426,047 246,651 2,577,133 260,108 136,356 30,341 88,937 515,742 8,060 151,725 270,782 85,905 14,276 283,045 1,329,535 3,906,668 Per Cent of Total Life in — Cost. 2.2 12.7 33.9 10.9 6.3 6.7 3.5 .2 3.9 6.9 2.2 .4 7.2 100.1 Years. 20 *20 20 20 20 Weight. 0.44 2.54 6.78 2.18 1.26 .94 .35 .08 .18 .02 .27 .69 .22 .02 .36 116.33 * Same as pipe. t Average life. CLASS C— TANK CARS. This class of equipment is of very stable construction, and it would appear that the maximum 20-year life can be accorded and a 5 per cent per annum depreciation established. MANUAL FOR THE OIL AND GAS INDUSTRY 73 CLASS C— REFINERIES. In order to arrive at a depreciation figure for the refinery as a whole, it is necessary to determine the relative investment in each item of equipment as compared to total investment. The various items have 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 divided into two classes, skimming plants and complete refineries — that is, refineries equipped with lubricating plants (but not having cracking plants). Figures for relative investment in each class of equipment were obtained from reports on valuation of refineries and from our own estimates. CALCULATED DEPRECIATION FOR WHOLE REFINERY. (a) Complete Refinery. Per Cent of Total Invest- ment. Rate of Depre- ciation. Product. Equipment: ) Per Cent. Distilling equipment (stills, condensers, agitatorS: etc.) 25 Power plant (boilers, engines, electrical equipment etc.) 15 Buildings 10 Storage (all kinds) 25 Pipes and fittings 10 Lubricating plant (filters, presses, chillers, grease plant, etc.) Miscellaneous ( . . . loading racks, machine shop, laboratory, etc.) Depreciation on refinery as a whole. Per Cent. 15 10 5 8 12 10 10 Per Cent. 3.8 1.5 .5 2.0 1.2 1.0 .5 10. (6) Skimming Plant. Distilling equipment. Power plant Buildings Storage Pipes and fittings. . . . Miscellaneous Depreciation on refinery us a whole. Per Cent. 35 10 5 35 10 5 Per Cent. 15 10 10 8 12 10 Per Cent. 5.3 1.0 .5 2.8 1.2 .5 11.3 74 MANUAL FOR THE OIL AND GAS INDUSTRY Refineries 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 relative 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 t ime Deprecia- tion Rate. Per Cent. 5 10 161 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 were based on what was considered the normal life of the plant, and no conditions that were purely local were taken into consideration. However, 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 sea- board that can be fed by tankers and pipe lines have an advanta- geous 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. 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 confronted with a new plant or competitor adjacent to the market that is able to undersell the products of the distant plant. The foreign niarket 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 rapidly must be con- MANUAL FOR THE OIL AND GAS INDUSTRY 75 sidered. Conditions of high humidity shorten the Hfe of ironwork and brickwork. High sulphur crudes cause stills and condensers to deteri- orate 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 Depart- ment 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 lubri- cating plant. For plants that have a complete refinery and in addition cracking plant, certain extra depreciation charges 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 : Life for Deprecia- tion. Annnual Deprecia- tion Hate. Tankers: Where such have been bought or built during the war period, that such cost be written off to $125 per D. W. ton and at that rate . Barges, harbor tugs, or other small floating equipment Filling stations: (1) Ordinary wood or corrugated construction (2) Brick and concrete, or extraordinary construction Distributing stations Tank wagons: Motor type Horse type Steel barrels Tracks and switches Years. 20 5 5 10 10 4 6 7 8 Per Cent. 5 20 20 10 10 25 161 14? 12J In considering depreciation on filling stations the factor to be given and most consideration is location. The normal life of equipment and buildings is at least 10 years, but unless the station is favorably situated it may only last 2 or 3 years. Note. — Filling stations arc divided into two classes: (a) 76 MANUAL FOR THE OIL AND GAS INDUSTRY Stations that have temporary wooden or corrugated iron buildings; and (b) stations that have buildings of brick or terra cotta, where the investment in buildings represents a large percentage of the total investment. Distributing stations with exception of delivery equipment do not depend to such a large extent on location, and for 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 per- centage of the investment in distributing stations and are short lived; therefore, in calculating depreciation on distributing sta- tions 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 when 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 equipment. It is believed that an average depreciation rate of 10 per cent or a life of 10 years will cover this class of equip- ment since equipment 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 drOling 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 8^ 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 annual rate of 14f Gathering stations 16| Field stations 25 M^ter? and regulators 20 MANUAL FOR THE OIL AND GAS INDUSTRY 77 The information at hand in which the cost of the equipment was taken into account showed that a natural gas plant could be depreciated, as a whole, at a rate of 10 per cent. It is a general consensus of opinion that the average Ufe 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 mainte- nance 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 17^ per cent per annum for aU 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 Ufe, 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. 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, Gush- ing, 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 thi-ee years. CLASS F.— NATURAL GAS GASOLINE PLANTS. Compression plants may be divided into compressors, engines, boilers, auxiliary equipment, cooling equipment, gathering and distributing hues, blending tanks, buildings, and electrical equip- ment. For absorption plants, separate items of absorbers, stills, con- densors, cooling equipment, auxihary equipment, boilers, engines, electrical equipment, tanks, and loading racks may be con- sidered. On the whole the average life of these plants is not over five or six years. 78 MANUAL FOR THE OIL AND GAS INDUSTRY 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 new plants or less than two years old, and of those operating at a loss almost all were over four years old. The returns of some 200 other plants were considered and are older plants, and were either not operating or were so defective in their detail as not to be usable for comparative purposes. In consideration of these data and other data at hand, it is recommended that: The original cost be placed on a 20 per cent salvage, and the remaining 80 per cent be depreciated in four years at 35, 20, 15, and 10 per cent in the respective years. SUMMARY. Class. No. Refer- ence. Page. A 1 GS 2 G8 3 C9 4 G9 5 70 6 70 7 70 8 70 9 71 10 71 Useful Life. Annual Depreciation. Drilling equipment Wells Dehydrators: Electric Pipe and tanks Tanks: Steel 5,000-55,000 bbls 2,500-5,000 Galvanized iron 500-2,500. Less than 500 Wood For movable tanks: Galvanized iron 500-2,500. Less than 500 For water tanks: 500-2,500 Less than 500 Tools Transportation equipment. . . . Water plants Electric equipment Machine shops Buildings: Small wood Frame structure Corrugated iron siding . . . . Concrete Brick Steel Years. 4 20 12 12 8 5 Per Cent. 40-25-15-10 20 50 5 8J 8J 20 llj 161 12J 20 331 33 J 10 10 14? 10 61 16^ 4 4 4 MANUAL FOR THE OIL AND GAS INDUSTRY 79 Summary — Continued. Class. No. Refer- ence. Useful Life. Annual Depreciation. B 1 1 1 1 2 3 4 5 6 7 1 Page. 71 72 73 75 76 77 Pipe lines: Mains over 6 inchrs diameter Mains under G inches diameter Years. 20 16 10 10 20 20 10 6 20 5 5 10 10 4 6 7 8 12 10 10 7 6 4 5 10 4 4 Per Cent. 4i 51 9 Less 10 per cent salvage. 10 c 5 Refineries: Class 1. — Located at point assuring a long supply of crude oil: or well-constructed plants Class 2. — Located at points assuring supply of crude oil for several years Class 3. — Skimming plants and small refineries of poor construc- tion, or located at points where supply of crude oil is not assured for a long 5 10 16! D Sales or marketing equipment: 5 20 • Filling stations — Class A. — Ordinary wood or cor- rugated steel con- struction Class B. — Brick and concrete or e.xtraordinary con- struction 20 10 10 Tank wagons — 25 161 14? 12} 8} E Track and switches Natural gas (utility companies) : Drilling equipment. (See A-1.) Wells. (See A-2.) Gas pipe lines — Gathering lines 10 10 161 25 F Meters and regulators Considered as a whole plant Natural gas gasoline: Plant — Compression, with 20 per cent 20 20 35-20-15-10 Absorption plants, with 20 per cent 35-20-15-10 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 pubUca- tions 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 producers 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 estimates of the underground reserves, and then the use ot, these two factors in the computation of proper depletion allow- ances. 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 purpose of making an intensive study of depletion. Records of production of thousands of properties were collected and tabu- lated. These were carefully gone over and studied by the most competent and experienced men in the country and the average future production curves and tables reproduced on succeeding pages of this manual are the result of their work. This study has confirmed the belief heretofore held that it is possible to make estimates of recoverable underground reserves of 80 MANUAL FOR THE OIL AND GAS INDUSTRY 81 oil within reasonably narrow limits. It has shown that in the making of such estimates it is simplest and safest to use some vari- ation of production curve methods, because by the use of the pro- ductive history of a well or property as a basis for a prediction of its future, estimation is confined to the future and the personal equa- tion thus reduced to a minimimi. Production curves and the methods for using them in making estimates of underground reserves are very fully described in sec- tion 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 production of a well or group of wells, and that the problem presented to the estimator is the extrapolation or exten- sion 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 decline curve for this purpose, because a careful comparison of production records shows that while the rate of decline in produc- tion varies widely over the country as a whole, when the production records from smaller units such as pools are tabulated, the decline rates of individual wells or properties show a striking similarity, although there may be wide variations in gross production figures. In view of this fact, the data collected are grouped according 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 is 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 prop- erty 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 pro- duction 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 82 MANUAL FOR THE OIL AND GAS INDUSTRY time interval required for such decline on each of the properties in the district. The average dechnes 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 computa- tion of averages, only the records of those wells which are ex- hausted, 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 construc- tion is entirely eliminated. This is only one of many methods devised for making an aver- age 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 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 and 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 approxi- mately 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 unknown MANUAL FOR THE OIL AND GAS INDUSTRY 83 factor in its equation, which is the slope of the Hne, definitely fixed in the earlier periods of production. This method of extra- polation 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 investi- gators working 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 operator to make special estimates, using any or all of the methods discussed 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 utmost, 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 knowledge 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 foundation to wliich it is rightfully entitled. Section A. METHODS OF ESTIMATING RECOVERABLE OIL RESERVES. Estimation of recoverable oil is possible. — The estimation of the future production of oil wells or of the recoverable oil underlying a property in the past has been considered an almost unsolvable problem, but scientific })rogress has disclosed reasonably accurate solutions, especially where sufficient dependal)le data are brought together and arranged in an orderly manner, for then it becomes evident that there is " a system to things " and that " freaks " are comparatively few. The recovery of oil is controlled by scientific 84 MANUAL FOR THE OIL AND GAS INDUSTRY laws, and where enough facts are known these laws make them- selves 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 ana- lyzed, it will be possible to make much closer estimates. Plotting production curves. — The production-curve method is one of the simplest and, when sufficient data are available, is, per- haps, the most accurate of all the methods for estimating the future production of oil wells. A production curve is a graphical record of the production 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 pre- pared for plotting in a production curve is given herewith. Year. Produc- tion. Wells Producing. Average per Well. Year. Produc- tion. Wells Producing. .\verage per Well. Barrels. Barrels. Barrels. Barrels. 1906 46,860 5 9,372 1912 2,462 G 410 1907 31,717 6 5,286 1913 1,641 6 274 1908 15,003 6 2,501 1914 1,061 6 177 1909 11,031 6 1,838 1915 578 6 96 1910 7,047 6 1,174 1916 218 6 36 1911 4,522 6 754 On a sheet of coordinate paper, as in Fig. 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 1,000 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 Figs. 1 and 2. Taking the record given, the first year is 1906, during which E:E . 1. toooo s /ooo /306 /30r /S08 /SC^ /3/0 /3JJ /9/Z /9/3 fS/4- /3/5 /$/6 19/7 /9/8 /S/S 111069--19. '"^- '-PRODUCTION DECLINE CURVE FOR A PROPERTY IN OKLAHOMA. ^^^ ,„^^ p^^^ ^^ :!^5 /S LINE /6 LINE 10000 -^ 9000 i-r-'T 1 :\ :; h J — h - t:::::i a:+i::::::::: 1 ::::::::::::::: ::::::::;:::::;::::;;g2t>:' I 1 ^ 8000 V^ 7000 lip ;== i; 1 i:::;::;:::;: ;? :::■:*:::-:■: i--t Aj^S? ::::::::::::::::::::::::::: ::::;::::;i:£l!: ii::;:::::;:;:;:::::::!::;;;;;;::;!??*^; :::: :::::::::::::::::::::: ::: :::::::s5S;^ K 6000 % 5000 qJ^ 4000 % :p:;|::;;;::;:;: Mi y 1 1 s;;:::::::: ;;; j :: % 3000 \ •^ ZOOO \ :^ /OOO :::::::::::::;::::::;: =ii :;; i: ::::::: + 1 .=i-_^i_ . . if-:;=::::;: :::::::::::::::::::::::::::::::::::-ze --± ± — -- M: /9// /9/2 /3/S /9/4 /&/S me /S/7 /9I8 J9I9 /S20 /S2/ J922 /S2? FIG. 2.— PRODUCTION DECLINE CURVE, SHOWING THE EXTENDED CURVE OF PROBABLE FUTURE PRODUCTION. /S24 /S25 (To face page 85.) MANUAL FOR THE OIL AND GAS INDUSTRY 85 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 distance representing 9,372 barrels above the bottom, which is 9 heavy lines and 3| light hnes. 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 hea\'y and 5 light lines above the bottom show the production of 2,501 barrels for that year. The production for the rest of the years are then plotted and th"^ points connected up by lines to make the curve as in Fig. 1. It will be observed at once that the plotted record makes a fairly regular and symmetrical curve. Manifestly, there is a certain relation between the production of the successive years that is not easily seen in the column of fig- ures 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 tJiousand production or decline curves have been plotted by petroleum engineers in the manner shown, and from this wide experience 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 period of production by continuing the curves in accordance with their symmetry and that such projections, if skillfully made, provide fairly trust- worthy estimates of the future production of the well. The estimation of the future production by the curves of past production is illustrated in Fig. 2. The actual record extends six years — from 1911 to 191G — 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 extension from which estimates of future productions 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 production is obtained. It is to be noted that production curves like Figs. 1 and 2 deal with actual facts and conditions on particular properties. Only the oil gauged is considered, hence all the various practical facts MANUAL FOR THE OIL AND GAS INDUSTRY 85 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 distance representing 9,372 barrels above the bottom, which is 9 heavy lines and 3f 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 hnes above the bottom show the production of 2,501 barrels for that year. The production for the rest of the years are then plotted and th-^ points connected up by lines to make the curve as in Fig. 1, It will be observed at once that the plotted record makes a fairly regular and symmetrical curve. Manifestly, there is a certain relation between the production of the successive years that is not easily seen in the column of fig- ures 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 engineers in the manner shown, and from this wide experience 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 period of production by continuing the curves in accordance with their symmetry and that such projections, if sldllfully made, provide fairly trust- worthy estimates of the future production of the well. The estimation of the future production by the curves of past production is illustrated in Fig. 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 extension from which estimates of future productions 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 estiniate of the total future production is obtained. It is to be noted that production curves like Figs. 1 and 2 deal with actual facts and conditions on particular properties. Only the oil gauged is considered, hence all the various practical facts 86 MANUAL FOR THE OIL AND GAS INDUSTRY 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 estab- lished the symmetry of the curve. This symmetry is not acci- dental but is the result of underlying natural laws governing the expulsion of the oil from the producing strata. In Fig. 1 it is evident that the production 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 care- fully 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 reliable 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 wells is estimated by comparison with the behavior of other wells in the same or similar districts that have produced long enough to establish trustworthy production curves. Usually the methods of estimation are based on the average behavior of the older wells because the behavior of the new wells will approxi- mate this average. 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 Fig. 3, is based on the relation that exists between the production of wells for their first year, and the quantities of oil they will produce ultimately. This MANUAL FOR THE OIL AND GAS INDUSTRY 87 particular figure was drawn from the production records of 209 properties in an Oklahoma field. As the average property in that field contains 10 producing wells, the figure may be said to repre- sent 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 production to determine the ultimate produc- tion for each property. The next step was to plot for each property the average production per well during the first j^ear or second year against the ultimate production of the well. Each dot, therefore, on Fig. 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 niany different sizes the first j^ear, 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 pro- duction. There is a considerable variation in ultimate produc- tion, 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 expected from wells of different output in this field. It shows that two wells in this field with the same production the first year may produce different totals, yet the amount that a well of a cer- tain 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 mininuun. Fig. 3 has been worked out on the law of averages similar to the fundamental laws underlying life insurance. Actuaries know, not by theory but from the analysis of great masses of data, the probable 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 88 MANUAL FOR THE OIL AND GAS INDUSTRY of 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. The method illustrated in Fig. 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 production of the well for the past year, can be worked out in the same manner. This fact is based on a conclusion for which there seems to be abundant statistical proof. This is as follows : If two wells under similar conditions produce equal amounts dur- ing any given year the amounts they will produce thereafter, on the average, will be 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 the 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 his- tories 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 produc- tion. This law of equal expectations makes possible the derivation of appraisal curves like Fig. 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 wells producing during that year. From this the aver- age production per well is computed. Readings are then made at the intersections of the vertical lines, representing the average yearly production per well with the curves, and the horizontal lines 2000 Prodi ■IG. 3.— / 300O /2000 /6000 £0000 ^4000 B&(^00 JZOOO JCOOO -40000 ^ooo - Production Per iVe// P/r^t >^^/~— 111009"— 19. FIG. 3.— APPRAISAL CURVE FOR ; HOMA OIL FIELD. ■^ooo -jsaoo (To face page 88.) MANUAL FOR THE OIL AND GAS INDUSTRY 89 on which these intersections lie are then followed to the right or left. This gives the maximum, average, and minimum ultimate pro- duction that may be expected per well. For example, if the wells average 30 barrels daily during any year, the 30-barrel line is fol- lowed vertically to the intersection with the jninimum 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 produc- tion, the year's production — 10,950 barrels — must be subtracted from these estimates. This gives the maximum, 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 production, as shown by the average ultimate produc- tion curves. These estimates of average future production were plotted and a curve drawn through the plotted points. In other cases the future-production curves were derived directly from the average-production curve. By multiplying these estimates of future production by the number of producing wells, the estimated future recovery for the developed portion of the property may be ascertained. It should be remembered, in using these future- production curves, that they represent the average and were based on all the evidence available. They do not take into con- sideration the increase in oil production due to the use of stim- ulative processes, such as compressed air, reshooting, flooding, etc. In the appraisal curve (Fig. 3) it is to be noted that though the limits of variation are set for a well of a particular size, these limits permit a considerable variation. If nothing is known beyond the first year's production, it will be necessary to assume that the well is an average well and the average curve should be used. The probabilities are that the well will actually be nearer the average than either extreme, as shown by the dots on Fig. 3. If, however, the record extends back two or more years it becomes possible to tell whether the well is an average well or if it deviates from the average the direction and degree of such deviation. In other words, the longer the past history of tlu> well, the more nearly MANUAL FOR THE OIL AND GAS INDUSTRY 89 on which these intersections lie are then followed to the right or left. This gives the maximum, average, and minimum ultimate pro- duction that may be expected per well. For example, if the wells average 30 barrels daily during any year, the 30-barrel line is fol- lowed vertically to the intersection with the minimum curve at 16,200, the average at 28,000, and the maxhnum at 40,500 barrels. Thus, the average 30-barrel well will produce not niore than 40,500 barrels, at least 16,200 barrels, but more likely it will produce approximately 28,000 barrels. To compute the future produc- tion, the year's production — 10,950 barrels — must be subtracted from these estimates. This gives the maximum, 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 production, as shown by the average ultimate produc- tion curves. These estimates of average future production were plotted and a curve drawn through the plotted points. In other cases the future-production curves were derived directly from the average-production curve. By nmltiplying these estimates of future production by the number of producing wells, the estimated future recovery for the developed portion of the property may be ascertained. It should be remembered, in using these future- production curves, that they represent the average and were based on all the evidence available. They do not take into con- sideration the increase in oil production due to the use of stim- ulative processes, such as compressed air, reshooting, flooding, etc. In the appraisal curve (Fig. 3) it is to be noted that though the limits of variation are set for a well of a particular size, these limits permit a considerable variation. If nothing is known beyond the first year's production, it will be necessary to assume that the well is an average well and the average curve should be used. The probabilities are that the well will actually be nearer the average than cither extreme, as shown by the dots on Fig. 3. If, however, the record extends back two or more years it becomes possible to tell whether the well is an average well or if it deviates from the average the direction and degree of such deviation. In other words, the longer the past history of the well, the niore nearly 90 MANUAL FOR THE OIL AND GAS INDUSTRY it can be classified according to its probable future behavior. If the record is long enough, a production curve like that shown in Fig. 2 may be used which will in such case be preferable to these general curves. In estimating the future production, the estimates should be revised at the end of each year instead of carrying for- ward errors from year to year. In this way poor estimates caused by lack of data or changed conditions on the property are not per- petuated. To show how these readjustments are made, the fol- lowing example is given: A property gave an average production of 12,410 barrels, or 34 barrels per well per day, during the first year. An average 34- barrel well in this field would produce a total of 30,500 barrels ultimately, of which 12,410 barrels (34X365) were produced during the first year. This leaves a future production of 18,090 barrels per well. In order to determine the average daily production for such a well during the second year, we must assume the figure of 18,000 barrels as its ultimate production. Applying the afore- said curve (Fig. 3), we follow the horizontal line representing this ultimate production across the chart to its intersection with the " average " curve. This gives 5,840 barrels, or 16 barrels as the first year's average daily production as a well with this ultimate production. Applying the law stated on page 88, it becomes evi- dent that the above figure of 16 barrels is approximatel}^ equal to the daily production for its second year of a well which produced 34 barrels daily during its first year. Multiplying 16 by 365 gives a total of about 5,840 barrels, which represents the amount pro- duced during the second year. The sum of the first and second year's production of this well is about 18,070. This amount deducted from the original ultimate production of 30,500 barrels leaves a future production of about 12,430 barrels. By repeat- ing the same process for each successive future year until the esti- mated ultimate production is extinguished, the total decline of this well will be obtained. Suppose the well actually produced 20 barrels per day, how- ever, instead of 16 barrels, or 7,300 barrels for the year instead of 5,640. This means that the well is above the average by 30 per cent, and proper corrections are therefore made. B}^ this means estimates may be corrected yearly and the depletion charges made more and more accurate as time goes on. Unusual cases will have to be dealt with separately. For MANUAL FOR THE OIL AND GAS INDUSTRY 91 instance, it may not be possible to niake trustworthy estimates of the future production of some wells by this method, because of the irregularity of their production. Also, those wells wherein stimu- lative process3s are used will have to be considered separately. Wherever the wells on a property produce regularly, however, and where the property is fairly well drilled up, and the proved acreage can be easily determined, the above method should be of great value to the oil producers in making estimates of future pro- duction The same general procedure may be applied in making esti- mates of the ultimate production of undrilled but proven oil land. Proven oil land is that which has been shoivn by finished wells, sup- plemented by geologic data, to be such that other wells drilled thereon are practically certain to be commercial producers. The average future production curve may be used in making estimates of the future production of a practically drilled up near-by similar tract and the ultimate production per acre estimated. These values, with necessary modifications, on account of position on structure, sand characteristics, drainage, etc., may be applied to the undrilled tract Another method is to estimate the first year's production of wells to be drilled on the proved land and determine their future by use of the average future production curve. The ultimate production of the tract is the sum of the future production and of the first year's production. Any estimates of the amount of oil that will be recovered from an undrilled but proven tract are subject to great inaccuracies. They are estimates in the truest sense of the word, but it is believed that this method is as satisfactory as any other for obtaining the probable productivity of a tract. No attempt has been made to cover all the ramifications of the problems of estimating the future production of wells or of the underground reserves of undrilled area. The purpose of this article has been, first, to point out that if sufficient data are col- lected and analyzed, the law of averages discloses systematic relations between the past and future production, and, second, to show one convenient method that may l)e used to estimate reserves as a basis for calculating depletion deductions in a sicentific manner. 92 MANUAL FOR THE OIL AND GAS INDUSTRY SECTION B. AVERAGE FUTURE PRODUCTION CURVES AND TABLES. FUTURE PRODUCTION CURVES FOR THE APPALACHIAN DISTRICT. The Appalachian oil and gas district occupies an elongated elliptical-shaped area extending northeast and southwest across the Appalachian Plateaus from southwestern New York to Ten- nessee, a distance of about 500 miles. In its broadest part, cen- tering in eastern Ohio, the district is about 150 miles wide. Thence northward and southward the productive zone rapidly diminishes in width, and its extension across Kentucky is by small, widely separated pools. The area of greatest oil development occupies a narrower zone which averages less than 50 miles in width and centers in the panhandle of West Virginia. The oil and gas bearing sands occur throughout a long strati- graphic interval, including rocks ranging in age from Ordovician to Carboniferous. The strata consist of preponderating shale, lenses of sandstone — which are the main oil and gas horizons — and subor- dinate limestone. The sandstones merge into shales toward the west, where there is also a greater proportion of limestone in the section. There is a marked decrease in thickness of the strata toward the west, notably of the Upper Devonian. This is shown by the increase in the interval between the Berea sandstone and the Corniferous limestone, from 500 feet in central Ohio to more than 5,800 feet in northern West Virginia. And southward across West Virginia there is a notable thickening of the Pottsville forma- tion. For this reason and because of the basin structure of the district the " Clinton " sandstone which occurs between two and three thousand feet beneath the surface in central Ohio is more than 7,000 feet deep in western Pennsylvania and northern West Virginia where it was not encountered in two recently sunk very deep test holes. The Appalachian oil and gas district lies in the geosyncline that extends between the Cincinnati anticline on the west and the zone of steeply folded rocks of the Allegheny Mountains on the east. The syncline is a spoonshaped trough in which the rocks rise north- westward, northward, and southeastward froni the lowest part of MANUAL FOR THE OIL AND GAS INDUSTRY 93 the basin situated in West Virginia near the southwestern corner of Pennsylvania. Superimposed on this larger structure are a series of folds by which the rocks are warped into irregular and generally nonpersistent anticlines and synclines, the axes of which undulate and overlap. The axial trend throughout the greater part of the district is northeast-southwest, but in southern West Virginia and Kentucky the trend becomes more westward. The folds decrease in intensity westward from the eastern margin of the district and west of the axis of the geosyncline the folding is so gentle that the rocks are warped into irregular wrinkles without marked axial trend. Along the western margin of the district the folds practically disappear and give way to a monocline on which the rocks rise westward at the rate of about 60 feet per mile. Considered as a whole, the most productive oil belt occurs con- tiguous to the central axis of the geosyncline and the largest accu- mulations of gas are found along the outer margins of the trough. But pools of oil and gas of varying size separated by nonproductive areas are irregularly distributed throughout the district. The pools are characteristically elongated in outline and their longer dimensions are prevailingly parallel to the structural trend. The location of most of the gas pools has been distinctly determined by structure. They occur along the crests of anticlines or along the updip termination of lenses of sandstone where they merge with shale, or where there is a marked decrease in porosity of the pay sand. The influence of structure on oil accumulation is also pronounced. In the absence of gas some oil pools occur on the crests of antichnes. Where much gas is present pools occur on the flanks of anticlines below the gas and above the edge water; others occur on terraces marked by changes in the rate of dip. In the absence of water in the rocks, petroleum tends to occur in the synclines. But in many pools the effect of structure is not so evident and lithology has been the controlling factor. The loca- tion of many of the oil pools in the Appalachian region is prin- cipally due to the position and porosity of the lenticular reservoir rocks. These factors account for the irregular shape of many of the pools and for their not uncommon occurrence " off structure." The petroleum from the Appalachian region is a high-grade paraffin oil. The product of New York, Ohio, Pennsylvania, and West Virginia has an average specific gravity not far from 0.800 (45° Baume) . The average for Kentucky is not quite so high. 94 MANUAL FOR THE OIL AND GAS INDUSTRY The total production of petroleum in New York, Pennsylvania, West Virginia, Kentucky, and Tennessee down to January 1, 1917, was 1,060,338,464 barrels. Complete data for the Appalachian region as a whole are not available because separate figures have not been kept for eastern Ohio district from the western part of the State, which is included in the Lima-Indiana district. The maximum annual output for New York and Pennsylvania was obtained in 1891, when more than 33,000,000 barrels were pro- duced. Since 1900 there has been a fairly uniform decrease in production down to 1912, when the lowest annual production, 8,712,076 barrels, was recorded for New York and Pennsylvania. In 1913 and 1914 there were slight increases and for the last five years the variation in production from year to year has been abnormally small. This change in rate makes the extension of the curve, in an endeavor to estimate future yield, somewhat doubtful. Nevertheless, because the peak production was at- tained so many years ago the extrapolated curve affords a good index of what may be expected in the future. The improbability of considerably extending the producing area is generally admitted and it does not seem likely that future discoveries will increase the present rate of production to any considerable extent. Extension of the production curve indicates that approxi- mately 85 per cent of the recoverable oil from New York and Pennsylvania has been exhausted under present operating con- ditions. Wells in the Appalachian i-egion are sunk by the standard or churn system of drilling. The rocks are hard and comparatively little casing is required as contrasted with drilling in the loosely consolidated rocks of other districts. The wells range in depth from a few hundred feet in parts of eastern Ohio and Kentucky to between 3,000 and 4,000 feet to reach the deeper sands in southern Pennsylvania and West Virginia. Bradford Sand, Cattaraugus and Allegany Counties, N. Y., and M^Kean County, Pa. The Bradford sand is one of the longest lived producers of the Appalachian district. It is of Upper Devonian age and is encoun- tered at depths ranging from 1,300 to 1,700 feet. The pay is unusually thick, averaging about 35 feet, and is commonly fine MANUAL FOR THE OIL AND GAS INDUSTRY 95 grained and homogeneous. Porosity averages 18 per cent by- volume. The curve is based on the records of tracts in most of which continuous production data go back to the opening of the field. A fair average of production for the entire field is a quarter of a barre' per well per day and many wells yield only one-tenth of a barrel per day. The curve shows estimated average future production without reference to flooding. The recent introduc- tion of the so-called " water drive " or flooding method of rejuve- nating old properties is accomplishing some remarkable results, but records do not go back far enough to warrant prediction as to ultimate production. ESTIMATED FUTURE PRODUCTION TABLE— BRADFORD SAND 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 30 300 2,450 800 4,700 50 250 400 2,950 900 5,050 100 850 500 3,400 1,000 5,400 150 1,400 600 3,8.50 1,250 6,100 200 1,800 700 4,300 1,500 6,600 250 2,150 Speechly Sand Pool, Concord Township, Butler County, Pa. The Speechly sand pool in Concord Township, Butler County, Pa., was opened up in 1902, as the result of deepening a well in an ESTIMATED FUTURE PRODUCTION TABLE— SPEECHLY SAND. 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. Average Production per Well During Tax- able Year. Estimated .Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. B.'incls. 50 300 1,800 800 4,3.')0 100 350 400 2,550 900 4,6.50 150 700 500 3,150 1,000 4,950 200 1,100 600 3,()00 1,2.50 5,.5.50 250 1,4.50 700 4,000 1,500 6,100 96 MANUAL FOR THE OIL AND GAS INDUSTRY old Fourth Sand pool. The wells range between 2,200 and 2,400 feet in depth and the spacing is approximately 7 acres per well. The sand is of Upper Devonian age and varies from 15 to 22 feet in thickness. The oil has a specific gravity of about 0.800 (45° B.) Hundred Foot Sand, Butler and Allegheny Counties, Pa. . The Hundred Foot is one of the principal sands in Butler and Allegheny Counties, Pa. The sand is persistent over large areas and ranges between 50 and 125 feet in thickness. It is usually medium grained, but is irregularly streaked with lenses of con- glomerate, which commonly are the pay streaks of which there may be several. Production from the Hundred Foot sand is charac- terized by the occurrence of considerable water which is pumped with the oil. It is of Upper Devonian age and is found at a depth of about 1,400 feet. The oil has a specific gravity of about 0.800 (45° B.) ESTIMATED FUTURE PRODUCTION TABLE— HUNDRED FOOT SAND. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels Barrels. Barrels. Barrels. Barrels. 50 300 1,300 800 3,000 100 300 400 1,700 900 3,250 150 600 500 2,050 1,000 3,600 200 850 600 2,3.50 1,250 4,.550 250 1,050 700 2,700 1,.500 5,650 Dorseyville Thirty-foot Pool, Allegheny County, Pa. This pool was opened up in 1913 and caused some excitement because of its occurrence in the midst of old development. Some of the wells had an initial monthly production of more than 7,000 barrels. The pay sand — the Thirty Foot of Upper Devonian age — is coarse grained and averages only about 8 feet in thickness. Production accordingly has fallen off rapidl3^ The wells range between 1,700 and 2,000 feet in depth. Wells are irregularly spaced and (kivclopment has been characterized by a number of dry holes. The oil has a specific gravity of about 800 (45° B.). MANUAL FOR THE OIL AND GAS INDUSTRY 97 ESTIMATED FUTURE PRODUCTION TABLE— DORSEYVILLE POOL. Average Production per Well During Year. Estimated Average Future Production per Well. Average Production per Well During Year. Estimated Average Future Production per Well. Average Production per Well During Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 800 800 2,750 1,900 100 100 900 900 3,000 2,050 150 150 1,000 950 3,500 2,300 200 200 1,250 1,100 4,000 2,500 250 300 1,500 1,250 4,500 2,700 300 350 1,750 1,400 5,000 2,900 400 450 2,000 1,550 6,000 3,300 500 550 2,250 1,650 7,000 3,600 600 650 2,500 1,800 8,000 3,950 700 750 Fifth Sand, Allegheny and Washington Counties, Pa. The Fifth sand of Upper Devonian age is one of the most important sands in the Appalachian region. It was the most productive horizon in the famous McDonald pool, in which a single well is credited with a total yield of more than 2,000,000 barrels. In Allegheny and Washington Counties, Pa., the Fifth sand aver- ages between 10 and 35 feet in thickness, and like most of the Appalachian oil sands varies considerably in porosity in nearby areas. The wells range between 2,200 and 2,500 feet in depth. ESTIMATED FUTURE PRODUCTION TABLE— FIFTH SAND. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 300 2,500 800 5,550 100 700 400 3,250 900 6,050 150 1,200 500 3,850 1,000 6,500 200 1,700 600 4,450 1,250 7,600 250 2,100 700 5,000 1,500 8,500 98 MANUAL FOR THE OIL AND GAS INDUSTRY Gordon Sand, Allegheny County, Pa. The wells average 2,100 feet in depth. The Gordon sand is of Upper Devonian age. ESTIMATED FUTURE PRODUCTION TABLE— GORDON SAND IN ALLEGHENY COUNTY, PA. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 300 1,300 800 3,450 100 250 400 1,750 900 3,800 150 500 500 2,250 1,000 4,200 200 750 600 2,700 1,250 5,050 250 1,050 700 3,100 1,500 5,800 Gordon Sand, Greene County, Pa. The Gordon is one of the main producing sands in Greene County. The average depth of wells is 3,000 feet, and the average thickness of the pay is 6 feet. The Gordon is of Upper Devonian age. ESTIMATED FUTURE PRODUCTION TABLE— GORDON SAND IN GREENE COUNTY, PA. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 600 2,250 1,750 5,250 100 200 700 2,550 2,000 5,800 150 450 800 2,850 2,250 6,400 200 650 900 3,150 2,500 6,950 250 900 1,000 3,450 2,750 7,550 300 1,100 1,250 4,050 3,000 8,100 400 1,500 1,500 4,650 3,500 9,200 500 1,900 t:: t:= * riiv t^ IfiOO t^OO ZfiOO 2^P9 ^000 ^veraffG Pracfucft'on per"- well cfuring Taxai^lG year-, /n Barrels. 111069"— 19. NG. 4. —ESTIMATED AVERAGE FUTURE PRODUCTION CURVES, APPALACHIAN FIEL (To face- pafie 99.) MANUAL FOR THE OIL AND GAS INDUSTRY 99 Fifty-foot Sand, Shinnston Pool, Harrison County, W. Va. This pool is credited with having some of the wells of largest initial production in West Virginia. A few are reported coming in at a rate between 450 and 550 barrels an hour. The pool underlies an irregular area of 1,530 acres, situated on a terrace on the western flank of the Chestnut Ridge antichne. Production is from the 50- foot sand. The pay streak is of Upper Devonian age and is of variable thickness and porosity, and averages possibly 15 feet. Wells are between 2,000 and 2,300 feet in depth, and for the entire pool have an average spacing of 10.7 acres per well. Individual tracts have produced at the rate of 22,000 barrels per acre. A single well has yielded more than 165,000 barrels. A total pro- dcction curve for the entire pool indicates that it is more than 90 per cent exhausted. The oil has a specific gravity of 0.797 (45.5° B.). ESTIMATED FUTURE PRODUCTION TABLE— SHINNSTON POOL. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 800 1,100 2,750 4,100 100 50 900 1,300 3,000 4,450 150 150 1,000 1,450 3,500 5,200 200 200 1,250 1,900 4,000 5,900 250 250 1,.500 2,2.50 4,500 6,550 300 350 1,750 2,650 5,000 7,250 400 500 2,000 3,050 6,000 8,500 500 650 2,250 3,400 7,000 9,500 600 800 2,500 3,750 7,500 9,850 700 950 Big Injun Sand, Roane County, W. Va. The Big Injun sand future production curve is based on the records of tracts situated in different parts of Roane County, W. Va. The sand averages about 40 feet in thickness and the pay possibly about 10 feet. The Big Injun sand is of Lower Car- MANUAL FOR THE OIL AND GAS INDUSTRY 99 Fifty-foot Sand, Shinnston Pool, Harrison County, W. Va. This pool is credited with having some of the wells of largest initial production in West Virginia. A few are reported coming in at a rate between 450 and 550 barrels an hour. The pool underlies an irregular area of 1,530 acres, situated on a terrace on the western flank of the Chestnut Ridge anticline. Production is from the 50- foot sand. The pay streak is of Upper Devonian age and is of variab'e thickness and porosity, and averages possibly 15 feet. Wells are between 2,000 and 2,300 feet in depth, and for the entire pool have an average spacing of 10.7 acres per well. Individual tracts have produced at the rate of 22,000 barrels per acre. A single well has yielded more than 165,000 barrels. A total pro- dcction curve for the entire pool indicates that it is more than GO per cent exhausted. The oil has a specific gravity of 0.797 (45.5° B.). ESTIMATED FUTURE PRODUCTION TABLE— SHINNSTON POOL. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 800 1,100 2,750 4,100 100 50 900 1,300 3,000 4,450 150 150 1,000 1,450 3,500 5,200 200 200 1,250 1,900 4,000 5,900 250 250 1,500 2,250 4,500 6,550 300 350 1,750 2,650 5,000 7,250 400 500 2,000 3,050 6,000 8,500 500 650 2,250 3,100 7,000 9,500 600 800 2,500 3,750 7,500 9,850 700 950 Big Injun Sand, Roane County, W. Va. The Big Injun sand future production curve is based on the records of tracts situated in different parts of Roane County, W. Va. The sand averages about 40 feet in thickness and the pay possibly about 10 feet. The Big Injun sand is of Lower Car- 100 MANUAL FOR THE OIL AND GAS INDUSTRY boniferoiis age and is found in this county at an average depth of 2,000 feet. ESTIMATED FUTURE PRODUCTION TABLE, BIG INJUN SAND, ROANE COUNTY, W. VA. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 600 1,950 1,750 5,400 100 200 700 2,300 2,000 6,100 150 400 800 2,600 2,250 6,750 200 550 900 2,950 2,500 7,400 250 750 1,000 3,250 2,750 8,050 300 900 1,250 4,050 3,000 8,650 400 1,250 1,500 4,750 3,500 9,700 500 1,600 Berea Sand, Lincoln County, W. Va. The wells tapping the Berea sands in Lincoln County, W. Va., range from 2,000 to 2,600 feet in depth, and the sand averages pos- sibly 20 feet in thickness. The Berea sand is of Lower Carbon- iferous age. ESTIMATED FUTURE PRODUCTION TABLE, BEREA SAND, LINCOLN COUNTY, W. VA. Average Production per Well During Last Taxable Year. Estimated Average Future Production per Well. Average Production per Well During Last Taxable Year. Estimated Average Future Production per Well. Average Production per Well During Last Taxable Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 600 2,600 2,000 5,550 100 450 700 2,850 2,250 0,050 150 750 800 3,100 2,500 6,550 200 1,050 900 3,350 2,750 7,000 250 1,300 1,000 3,550 3,000 7,450 300 1,500 1,250 4,050 3,500 8,250 400 1,900 1,500 4,600 4,000 8,900 500 2,250 1,750 5,100 1 MANUAL FOR THE OIL AND GAS INDUSTRY 101 Gordon Sand, Wetzel County, W. Va. The Gordon sand is the source of much oil in Wetzel County. The average depth of wells is 3,100 feet and the average thickness of the pay is 7 feet. The Gordon sand is of Upper Devonian age. ESTIMATED FUTURE PRODUCTION TABLE, GORDON SAND IN WETZEL COUNTY, W. VA. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 600 2,350 2,000 5,950 100 250 700 2,700 2,250 6,500 150 450 800 3,050 2,750 7,400 200 700 900 3,350 3,000 7,800 250 900 1,000 3,650 3,500 8,550 300 1,150 1,250 4,250 4,000 9,300 400 1,550 1,500 4,900 500 1,950 1,750 5,400 Berea Sayid, Jefferson, Belmont, and Monroe Counties, Ohio. Only a few records of Berea sand production extending over a number of years were obtained in eastern Ohio. The curve shown is based on the records of properties situated in Jefferson, Belmont, and Monroe Counties. The pay sand is about 20 feet thick and the wells range from 1,400 to 2.000 feet in depth. ESTIMATED FUTURE PRODUCTION TABLE, BEREA SAND IN JEFFERSON, BELMONT, AND MONROE COUNTIES, OHIO. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Average Production per Well During Tax- able Y'ear. Estimated Average Future Production per Well. Average Production per Well During Tax- able Y'ear. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 300 1,050 800 2,725 100 200 400 1,450 900 3,000 150 450 500 1,800 1,000 3,500 200 650 600 2,150 1,2.50 3,8.50 250 850 700 2,450 1,500 4,450 102 MANUAL FOR THE OIL AND GAS INDUSTRY Keener Sand, Jackson Ridge Pool Monroe County, Ohio. The sand is between 25 and 40 feet thick and the pay averages 12 feet. The wells are not large producers, but they have " good staying qualities." They average 1,450 feet in depth. The Keener sand is of Lower Carboniferous age. ESTIMATED FUTURE PRODUCTION TABLE— JACKSON RIDGE POOL. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 300 2,050 800 4,700 100 450 400 2,700 900 5,100 150 900 500 3,300 1,000 5,550 200 1,275 600 3,800 1,250 6,550 250 1,650 700 4,250 1,500 7,500 Keener Sand, St. Mary's Pool, Washington County. Ohio. The pay is 8 feet thick and the wells average 1,650 feet in depth. ESTIMATED FUTURE PRODUCTION TABLE— ST. MARY'S POOL. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 800 1,700 2,750 3,650 100 150 900 1,850 3,000 3,850 150 300 1,000 2,000 3,500 4,250 200 450 1,250 2,300 4,000 4,600 250 600 1,500 2,550 4,500 4,955 300 750 1,750 2,750 5,000 5,200 400 1,000 2,000 3,000 6,000 5,750 500 1,250 2,250 3,200 7,000 6,220 600 1,400 2,500 3,450 8,000 6,700 700 1,600 MANUAL FOR THE OIL AND GAS INDUSTRY 103 Clinton Sand, Gore Pool, Perry and Hocking Counties, Ohio. The Gore pool in the Chnton sand in Perry and Hocking Counties. Ohio, was opened up in 1911. It is a westward exten- sion of the New Straitsville pool. Up to 1918, 134 wells had been drilled in the Gore pool with an average spacing of approximately 10 acres per well. The pay sand ranges from 3 to 25 feet in thick- ness and averages about 15 feet. The wells are between 2,900 and 3,300 feet deep. The oil has a gravity of 46° Baumc. The Clinton sand is of Silurian age. ESTIMATED FUTURE PRODUCTION TABLE— GORE POOL. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 800 1,100 2,750 3,550 100 50 900 1,250 3,000 3,800 150 150 1,000 1,400 3,500 5,300 200 200 1,250 1,750 4,000 4,700 250 300 1,500 2,100 4,500 5,100 300 350 1,750 2,450 5,000 5,500 400 500 2,000 2,750 6,000 6,200 500 6.50 2,250 3,000 7,000 0,900 600 800 2,500 3,300 8,000 7,550 700 950 Clinton Sand, Wayne and Hocking Couyities, Ohio The walls vary in depth between 3,000 and 3,500 feet and the average thickness of the pay sand is 20 feet. The Clinton sand is of Silurian age. 104 MANUAL FOR THE OIL AND GAS INDUSTRY ESTIMATED FUTURE PRODUCTION TABLE— CLINTON SAND, HOCKING AND WAYNE COUNTIES, OHIO. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 800 1,100 2,750 4,200 100 50 900 1,300 3,000 4,450 150 75 1,000 1,450 3,500 5,050 200 100 1,250 1,950 4,000 5,550 250 150 1,500 2,350 4,500 6,050 300 200 1,750 2,750 5,000 6,500 400 350 2,000 3,150 6,000 7,400 500 500 2,250 3,550 7,000 8,200 600 700 2,500 3,850 8,000 8,900 700 900 Ragland Field, Bath County, Ky. The field was discovered in 1900 and was mainly drilled up by 1904, though occasional sporadic drilling is still done. The sand is the Corniferous limestone of Devonian age, which averages from 12 to 20 feet in thickness. Its depth is 300 to 380 feet in the Licking River Valley and 500 feet more on the hilltops. The oil occurs in a flat anticline with northeast-southwest axis and with the oil in that portion of the sand lying between 250 and_300 feet above sea level. The general dip of the rock is to the southeast, and a few miles to the northwest of the field the oil sand crops out at the surface. These is very little gas with the oil. The gravity is about 26° to 27° Baume. ESTIMATED FUTURE PRODUCTION TABLE— RAGLAND POOL Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Average Production per Well During Ta.x- able Year. Estimated Average Future Production per Well. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 400 1,850 1,000 4,050 100 300 500 2,300 1,250 4,750 150 600 600 2,750 1,500 5,400 200 850 700 3,100 1,750 6,000 250 1,100 800 3,450 2,000 0,400 300 1,400 900 2,750 3,000 6,900 MANUAL FOR THE OIL AND GAS INDUSTRY 105 Floyd County, Ky. The future production curve of Floyd County, Ky., Is based on production from properties representing several sands of Carbonif- erous age. These arc the Beaver, Horton, Pike or Mason, and the Salt sands. There are no pronounced surface structures; oil and gas moving northwestward up the dip have apparently been stopped either by slight terraces or by tight places in the sand. Dry holes are numerous. Initial production is small but is well maintained. The gravity is about 40° Baume. ESTIMATED FUTURE PRODUCTION CURVE, FLOYD COUNTY, KY. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 400 1,800 1,000 4,950 100 250 500 2,300 1,250 6,300 150 500 600 2,850 1,500 7,600 200 750 700 3,400 1,750 8,700 250 1,050 800 3,900 2,000 9,750 300 1,300 900 4,450 Beaver Creek Sand, Wayne County, Ky. The Wayne County field consists of a number of small pools to which separate local names are given. The earliest wells were drilled between 20 and 25 years ago, and some drilling is still going on. The principal oil-bearing horizon is a cherty geodal limestone known as the Beaver Creek sand. It lies just above the Chatta- nooga shale and fornis the basal number of the Waverly or Missis- sippian. This limestone varies greatly in thickness, texture, and porosity, and the production of wells varies accordingly. It lies 400 to 600 feet beneath the valleys, while the hills rise from 300 to 600 feet higher. Structurally the oil favors the sides and bot- toms of synclinal troughs that slope gently eastward. 106 MANUAL FOR THE OIL AND GAS INDUSTRY ESTIMATED FUTURE PRODUCTION TABLE, WAYNE COUNTY, KY. 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. Average Production per Well During Tax- able Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 800 1,450 3,000 3,850 100 100 900 1,600 3,500 4,300 150 250 1,000 1,750 4,000 4,700 200 350 1,250 2,050 4,500 5,100 250 450 1,500 2,350 5,000 5,450 300 550 1,750 2,650 6,000 6,200 400 750 2,000 2,900 7,000 6,900 500 950 2,250 3,150 8,000 7,600 600 1,150 2,500 3,400 700 1,300 2,750 3,600 Irvine Field, Estill County, Ky. The Irvine field extends from near Irvine, Estill County, Ky., northeastward 12 miles and is 1 to 2 miles wide. Present evelop- ment began in 1915. The field lies on the southeast of a fault from which the rocks dip to the southeast. The producing sand is a ESTIMATED FUTURE PRODUCTION TABLE— IRVINE POOL. Average Production per Well During Last Taxable Year. Estimated Average Future Production per Well. Average Production per Well During Last Taxable Y'ear. Estimated Average Future Production per Well. Average Production per Well During Last Taxable Year. Estimated Average Future Production per Well. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 50 800 1,000 3,000 2,250 100 150 900 1,100 3,500 2,400 150 250 1,000 1,200 4,000 2,550 200 350 1,250 1,350 4,500 2,650 250 450 1,500 1,550 5,000 2,750 300 500 1,750 1,700 6,000 2,950 400 650 2,000 1,800 7,000 3,100 500 750 2,250 1,950 8,000 3,200 600 850 2,500 2,050 700 950 2,750 2,150 MANUAL FOR THE OIL AND GAS INDUSTRY 107 porous magnesian limestone of Corniferous (Devonian) age, with the pay usually in the upper few feet. The sand near Irvine is about 20 to 30 feet thick and lies only 100 to 200 feet beneath the surface of the valleys, but in the hills 600 to 800 feet deeper. The gravity of the oil is about 33° Baume. FUTURE PRODUCTION CURVES FOR LIMA-INDIANA AND ILLINOIS-INDIANA FIELDS. The Lima-Indiana field comprises about 230,000 acres in north- western Ohio and about 41,000 acres in northeastern Indiana. The productive areas in this field occur in low domes over the broad crest of the Cincinnati uplift, or in domes or terraces or other minor convexities on its flanks. The oil is obtained from lenses or discontinuous layers in the Trenton hmestone, where the original limestone has been changed to a porous dolomite, at depths varying with the distance from the crest of the arch, with the dip of strata, and the depth below the top of the formation. Wherever the Trenton limestone ceases to be dolomitic it ceases to be oil bearing. This Trenton limestone is from 450 to 600 feet thick, and the oil is usually found within 100 feet of the top, although in a few places, as in Grant and Delaware Counties, Ind., and Seneca County, Ohio, oil has been found as low as 250 to 400 feet in the Trenton. The best pay, however, is generally believed to be less than 40 feet below the top of the formation. Often two pay streaks occur in the upper part of the Trenton, the first 10 to 15 feet below the top and the second about 20 feet lower. It seems that the productive lenses found at greater depth do not occur at definite levels. The existence of oil in the Trenton limestone of Ohio was dis- covered in 1885 and many wells were drilled the following year. The earlier developments were at Findlay in Hancock County, North Baltimore in Wood County, and Lima in Allen County. The greater part of the production has come from Wood, San- dusky, and Hancock Counties, but Allen, Mercer, Auglaize, Lucas, Ottawa, Seneca, Van Wert, and Darke Counties have also con- tributed important quantities. The finding of oil in northwest Ohio in 1885 stunulatcd prospect- ing farther west in Indiana. In 1889 two producing wells were drilled in Blackford County and in 1890 several wells were brought in in Wells County, and from that date the field was rapidly ex- 108 MANUAL FOR THE OIL AND GAS INDUSTRY tended. The greater part of the Trenton oil production in Indiana has come from Adams, Blackford, Delaware, Grant, Huntington, Jay, Randolph, and Wells Counties. Of these, Grant County has been, perhaps, the greatest producer. The pools in the Trenton rock district are very irregular in shape, differ greatly in size, and often entirely surround barren areas. While, of course, the varying characteristics of the pools do not follow arbitrary lines, it was found best in making a study of this district to make each county a pool unit. The main Illinois-Indiana field is about 70 miles long and has a maximum width of about 20 miles. It extends in a slightly north- west-southeast direction from the vicinity of Westfield in north- western Clark County through Clark, Crawford, and Lawrence Counties to the neighborhood of St. Francisville. These are outliers or extensions in Coles, Cumberland, and Jasper Counties, but the three first named have produced by far the greater portion of the oil. In Indiana the field extends across the Wabash River into Gib- son, Pike, and Sullivan Counties. Nearly all the production is found in structural undulations on the east flank of the La Salle anticline, which begins near La Salle in the northern part of the State and follows generally the trend of production as given above. This great arch is asymmetrical, the western limb being much more steeply inclined than the eastern. In the southern part of Lawrence County it appears to flatten out, and a few miles below St. Francisville it breaks up and disappears. Development in eastern Illinois began with a well drilled near Casey, in Clark County, which produced about 35 barrels a day from a sand found at a depth of less than 400 feet. This was in 1904, and by the end of 1905 more than a thousand barrels a day were being marketed. From this on development has been rapid. The producing sands in the north end of the field are shallow, occurring in the Pennsylvanian series at depths of from 300 to 400 feet. Farther south productive sands are found much lower stratigraphically, and lie at greater depths — the deeper ones occurring in the Chester and St. Genevieve (Upper Mississippian) formations. The richest oil-producing area in the field is in Lawrence County where seven sands arc encountered at depths ranging from 450 to 2,000 feet, with the richest sand on the bottom. MANUAL FOR THE OIL AND GAS INDUSTRY 109 Besides the field on the slopes of the La Salle anticline there are three or four minor pools on the western side of the great Illinois basin — those of Sandoval in Marion County, and Carlyle in Clin- ton County, perhaps being the best known. Besides those there are the Allendale pool in Wabash County and the Colmar pool in McDonough County which have produced considerable quantities of oil. Productive areas, like those elsewhere, are irregular in shape and of varying characteristics. It was found that separation into county " pool units " as in the Lima-Indiana field was not feasible, as there are sometimes two or three variant pools in a county. In some cases, however, as in Crawford County, two or three or more " pools " of the same general character were combined into one. In Clark County there are two pools, both in the shallow Penn- sylvanian sands — the Westfield pool on the north and the John- son Township pool south and east of the Westfield. Immediately to the southwest of the Westfield pool and west of the Johnson Township pool Hes the Siggins pool, which is almost all in Cum- berland County. In Crawford County are a number of small pools without much difference, and of these have been grouped together the Robinson, Kibbie, Oblong, Honey Creek, and Hardinsville, under the name " Robinson pool." In southeast Crawford County there are three outlying pools, Duncanville, Flat Rock, and Birds, which have been grouped together under the name of Birds-Flat Rock pool. In Lawrence County all the pools in the upper part of the county, Nuttall, Applegate, Bridgeport, Lawrenceville, etc., have been grouped as the Upper Lawrence County pool, and in the south are the Kirkwood and Dennison pools. Other pools in Illinois are the Plymouth or Colmar pool in McDonough County, the Sandoval pool in Marion County, the Carlyle pool in Clinton County, and the Allendale pool in Wabash County. The work preparatory to the construction of estimated future production curves in the producing areas in the Lima-Indiana and Illinois-Indiana fields consisted in the inspection of all available production records and the selection of those considered typical of the various pools and localities, the tabulation of these records, drawing of dechne curves for individual leases, and finally the com- 110 MANUAL FOR THE OIL AND GAS INDUSTRY bination of all these decline curves into an average decline curve for the field or pool. In the Lima-Indiana field were found very few records of pro- duction prior to 1908. Some companies had never kept proper records and other had destroyed all their old books, so the work was somewhat handicapped in this regard. However, the pro- duction records for the past 10 years were very full and complete, and it is on these records that curves are based. The " average well " was adopted as the unit for tabulation and estimating and the " average decline curve," which seems to meet all the requirements of the situation, was devised for use in extend- ing the individual lease production curves to their limit of profit- able production, and also in constrcting the estimated future production curve. In the Illinois-Indiana field, which is younger than the Lima- Indiana field, were found excellent production records from the early life of the field. The same methods in handling the records were used as in the Lima-Indiana field and the same kind of curves drawn. In all the records of more than 2,000 leases, comprising about 40 per cent of the producing area, were tabulated and studied and the resultant curves as presented herewith are believed to be fairly representative. 3JJW 1 -- PSW^W 3: ii cq:-b±n 144 If;;;;:;:; ^ = E-- ff ± — 4«» Z,SW} 1,000 --- " " : """±"3: X : ''-\ :;: = ,' :::::::: :::::::-; = ?:::::::::::::!:: ILmTl bHT| rill liTTMl - - — -' ''r ■ :i:|iq ILU ptm±^|||||i||||| ^^wlwpiliitiiM ::-:i-;i!:|f=:i;;;;:;;;:|; t.ooo :::::::::::;:::::::;:::::::::::::::::;:::::::::::::':: il lllliii Si 5^ IN?: ..... rHiS ^mniu ;:::;:::::::::::::;::::::::::::::: ' M 100 ISO ZOO !S0 \0 «0 «» iOO sso ««> - «» KW ISO Mi A^'erage. Production per i ve/l during Ta? ■*_ -/ 7 1 / J t 2 / .x\^ i ^^ .^^ ~\wX Ja^H^?t i'l> / :^y . - - .-.-. ^^ft ^y _ iTN^zr ^ 2 i<$^Z %y^ " / .N»y y. ^ r 4000 - y~ ^ ' **. j<^ j^^ _^' , ,1 , , t^" \ qi , .. _,. , ,. . „ „ 1 . 60,000 100,000 120,000 140,000 160,0 Well during Taxable Year, in Barrels (To face page 171.) 80,000 100,000 120,000 140,000 160,000 Well during Taxable Year, in Barrels (To face page 171.) »-=- — - ^^^ r ' 1 ■ ..--^^^ ■ '[ y^ t -r- y / ^t ±__T- X ; : L _ -/- _^ , / ■ : : |5^;r;:' ^ , / :_: % "^il/ •.\ --j— ^'1/ if. ■ r ---m ■ : ;|„„-..- ■ ■ ■:■;■■, '-^ ^^^ - ■ ^;;i^^^^ 3n,m0 40,000 60.000 80.000 100.000 120.000 140,000 lOO.i Average Production per Well during Taxable Year, in Barrels (To face page 171.) MANUAL FOR THE OIL AND GAS INDUSTRY 171 SOUR LAKE. Average Average Average Production per Wrll Last Month of Taxable Estimated Future Production. Production per Well Last Month of Taxable Estimated Future Production. Production per Well Last Month of Taxable Estimated Future Production. Year. Year. Year. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 41 50 600 10,000 2,000 27,840 50 185 700 11,750 2,500 20,700 75 765 800 13,550 3,000 32,900 100 1,600 900 15,280 4,000 37,200 150 2,800 1,000 16,870 5,000 41,000 175 3,200 1,100 17,870 6,500 46,300 200 3,750 1,200 20,100 7,000 47,000 250 4,500 1,300 21,400 8,000 51,500 300 5,300 1,400 22,600 9,000 56,000 350 6,000 1,500 23,900 10,000 61,000 400 6,800 1,700 25,540 11,000 66,000 500 8,375 1,900 27,240 12,000 71,000 Batson. Produces from irregular sands as in Saratoga and Sour Lake from depths of 200 to 1,500 feet. Wells constantly reworked but some wells producing in 1908 are still productive in 1918. BATSON. Average Production per Well Last Month of Taxable Year. Estimated Future Production Average Production per Well Last Month of Taxable Year. Estimated Future Production Average Production per Well Last Month of Ta.\able Year. Estimated Future Production Barrels. Barrels. Barrels. Barrels. Barrels Barrels. 20 250 7,680 1,500 23,000 25 40 300 9,180 1,750 24,300 50 380 400 12,260 2,000 25,400 75 890 500 13,960 2,500 27,000 100 1,630 750 17,000 3,000 27,900 150 3,760 1,000 19,400 4,000 29,100 200 5,830 1,250 20,400 5,000 30,700 MANUAL FOR THE OIL AND GAS INDUSTRY 171 SOUR LAKE. Average Production per Well Last Month of Taxable Estimated Future Production. Average Production per Well Last Month of Taxable Estimated Future Production. Average Production per Well Last Month of Taxable Estimated Future Production. Year. \ ear. Year. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 41 50 600 10,000 2,000 27,840 50 185 700 11,750 2,500 20,700 75 765 800 13,550 3,000 32,900 100 1,600 900 15,280 4,000 37,200 150 2,800 1,000 16,870 5,000 41,000 175 3,200 1,100 17,870 6,500 46,300 200 3,750 1,200 20,100 7,000 47,000 250 4,500 1,300 21,400 8,000 51,500 300 5,300 1,400 22,600 9,000 56,000 350 6,000 1,500 23,900 10,000 61,000 400 6,800 1,700 25,540 11,000 66,000 500 8,375 1,900 27,240 12,000 71,000 Batson. Produces from irregular sands as in Saratoga and Sour Lake from depths of 200 to 1,500 feet. Wells constantly reworked but some wells producing in 1908 are still productive in 1918. BATSON. Average Production per Well Last Month of Taxable Year. Estimated Future Production Average Production per Well Last Month of Taxable Year. Estimated Future Production Average Production per Weli Last Month of Taxable Year. Estimated Future Production Barrels. Barrels. Barrels. Barrels. Barrels Barrels. 20 250 7,680 1,500 23,000 25 40 300 9,180 1,750 24,300 50 380 400 12,200 2,000 25,400 75 890 500 13,960 2,500 27,000 100 1,630 750 17,000 3,000 27,900 150 3.760 1,000 19,400 4,000 29,100 200 5,830 1,250 20,400 5,000 30,700 172 MANUAL FOR THE OIL AND GAS INDUSTRY Edgerly, Vinton and Evangeline. These are typical salt-dome pools which have been ex- hausted except for the stray sands and an occasional pocket of oil in the cap rock. Production is extremely erratic and the deviation from the averages given in the table is large. EDGERLEY. Average Average Average Production per Well During Taxable Estimated Future Production. Production per Well During Taxable Estimated Future Production. Production per Well During Taxable Estimated Future Production. Year. Year. Year. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 7,000 4,000 15,000 56,800 60,000 140,100 7,250 6,000 20,000 65,300 75,000 151,300 7,500 10,000 25,000 74,000 90,000 160,950 8,000 20,120 30,000 87,200 100,000 166,500 9,000 34,700 35,000 99,500 120,000 177,100 10,000 44,000 40,000 110,800 135,000 185,200 11,000 48,240 '50,000 129,100 150,000 192,140 VINTON. Average Production per Well Last Month of Taxable Year. Estimated Future Production. Average Production per Well Last Month of Taxable Year. Estimated Future Production. Average Production per Well Last Month of Taxable Year. Estimated Future Production. Barrels 250 300 400 500 600 700 800 900 Barrels. 250 860 1,780 2,800 4,025 5,700 7,000 Barrels. 1,000 1,100 1,200 1,350 1,500 1,750 2,000 Barrels. 8,500 10,800 12,400 14,600 17,400 20,400 23,900 Barrels. 2,250 2,500 2,750 3,000 3,500 4,000 4,500 Barrels 28,100 32,650 37,000 40,600 43,800 47,600 51,150 For Spindle Top, Anse Le Butte and Welch, the use of the Evangeline table is suggested. For Damon Mound and Big Hill, Hull, the use of the Goose Creek table is suggested. 4 m 5.000 er Well 2,000 3,000 Average Production per Well during Last Month of Taxable Year, in Barrels (To face page 172.) MANUAL FOR THE OIL AND GAS INDUSTRY 173 For Markham, the use of the Humble Shallow sand table is suggested. Sufficient data for the compilation of a table are lacking in these fields. In any case where the production for one w^ell per month is above that given in the table, use the Goose Creek Table. EVANGELINE. Average Average Average Production per Well Last Month of Taxable Estimated Future Production. Production per Well Last Month of Taxable Estimated Future Production. Production per Well Last Month of Taxable Estimated Future Production. Year. Year. Year. Barrels. , Barrels. Barrels. Barrels. Barrels. Barrels. 160 700 10,020 2,000 31,500 200 340 800 12,900 2,500 40,000 250 980 900 13,900 3,000 47,000 300 1,400 1,000 15,900 4,000 56,200 350 2,400 1,100 17,580 5,000 62,100 400 3,200 1,200 19,000 6,000 67,100 450 4,370 1,300 21,080 7,000 71,100 500 5,630 1,400 22,380 8,000 74,600 550 6,570 1,500 25,200 9,000 77,100 600 7,700 1,750 27,700 10,000 78,770 650 9,930 MEXICAN OIL FIELDS. General features. — The known oil fields of Mexico are included within two great regions, both of which are segments of the Gulf Coastal Plane, Tampico-Tuxpam, and Tehuantepec-Tabasco regions. They cover approximately 20,000 to 30,000 square miles and include some 20 local fields. A very rough estimate places the proved area in the two regions at 25 square miles, the prospective area at 500 to 1,000 square miles. Inasmuch as less than 1,000 wells have been drilled for oil in the entire Republic up to the pres- ent time, and as a great bulk of the oil has come from two wells, it would be rash indeed to give too much weight to estimates of unit areas. The principal oil-yielding rocks are limestones or limy shales of Cretaceous or Eocene age. Some oil is found in the later Tertiaries in the southern region. Fields are generally anticlinal in struc- MANUAL FOR THE OIL AND GAS INDUSTRY 173 For Markham, the use of the Humble Shallow sand table is suggested. Sufficient data for the compilation of a table are lacking in these fields. In any case where the production for one w^ell per month is above that given in the table, use the Goose Creek Table. EVANGELINE. Average Production • per Well Last Month of Taxable Year. Estimated Future Production. Average Production per Well Last Month of Taxable Year. Estimated Future Production. Average Production per Well Last Month of Taxable Year. Estimated Future Production. Barrels. Barrels. Barrels. Barrels. Barrels. Barrels. 160 700 10,020 2,000 31,500 200 340 800 12,900 2,500 40,000 250 980 900 13,900 3,000 47,000 300 1,400 1,000 15,900 4,000 56,200 350 2,400 1,100 17,580 5,000 62,100 400 3,200 1,200 19,000 6,000 67,100 450 4,370 1,300 21,080 7,000 71,100 500 5,630 1,400 22,380 8,000 74,600 550 6,570 1,500 25,200 9,000 77,100 600 7,700 1,750 27,700 10,000 78,770 650 9,930 MEXICAN OIL FIELDS. General features. — The known oil fields of Mexico are included within two great regions, both of which are segments of the Gulf Coastal Plane, Tampico-Tuxpam, and Tehuantepec-Tabasco regions. They cover approximately 20,000 to 30,000 square miles and include some 20 local fields. A very rough estimate places the proved area in the two regions at 25 square miles, the prospective area at 500 to 1,000 square miles. Inasmuch as less than 1,000 wells have been drilled for oil in the entire Republic up to the pres- ent time, and as a great bulk of the oil has come from two wells, it would be rash indeed to give too much weight to estimates of unit areas. The principal oil-yielding rocks are limestones or limy shales of Cretaceous or Eocene age. Some oil is found in the later Tertiaries in the southern region. Fields are generally anticlinal in struc- 174 MANUAL FOR THE OIL AND GAS INDUSTRY ture, but in some instances the structure has not yet been deter- mined. The underground reservoirs are associated with volcanic intrusions. The oldest development of importance began in 1906, but the larger wells were not developed until four or five years later. The wells average in depth 2,500 feet and in production from 50 to over 100,000 barrels daily. The oils range in gravity from 10° to 14° Baume in the Panuco field and from 15° to 29° Baume in the others, the average for the most productive field, the Tepetate, being about 21° or .927 specific gravity. The oil is usually accompanied by large quantities of wet gas. Estimates of from 4,000,000 to 12,000,000 cubic feet of gas daily being yielded by some of the wells. Both the rotary hydraulic and standard cable systems of drilling are used. The first and most general use for the Mexican crude oil aside for supplying oil for refining for local trade has been as fuel oil. Most of the oil is exported to the United States or other countries. Statement regarding depletion allowanceSc — The depletion of the oil reserves in the Mexican fields is an unquestionable fact, but owing to the large volume of oil produced by the commercially successful wells and to restricted transportation facilities, it is at present and has been during past years, impossible to show the actual diminution of flow. In other words, the existing pipe-line systems in connection with the available tank steamer fleets can not transport the oil out of Mexico as fast as the wells are capable of producing it. Obviously, at some future time the diminution in the oil flow or the increase in transportation or storage capacities will reach a point where the decline in production of the large wells is actually shown, but for present purposes in estimating allow- ances for depletion there is little or nothing in the shape of pro- duction decline records on which to base an estimate of the prob- able future production of the large Mexican oil wells and one is therefore confronted at the outset by an almost complete lack of records essential in computing the fundamental unknown factors in the problem. Were one to compute at present the depletion of the large Mexican oil wells, which yield the bulk of the marketed oil, on the basis of the diminution of flow, he would arrive in most cases at the incongruous conclusion that no depletion takes place even though the well might be producing millions of barrels per year. ^^ ^ C/ased or f?ock Pressure Dec/ine. "IG. 13.— REPRESENTATIVE CLOSED PRESSURE DECLINE CURVES FOR GAS V/ELLS AND POOLS IN VARIOUS PARTS OF THE UNITED STATES. SEE PAGES 31 MANUAL FOR THE OIL AND GAS INDUSTRY 175 With this in mind we must be sure at the outset that (any estimates of probable depletion of the content of Alexican oil land, being based almost entirely on more or less plausible conjectures) any estimates of depletion of necessity presuppose a previous knowledge of the probable amount of oil underground in any par- ticular property, and although here again we are confronted with the lack of sufficient data on which to base accurate conclusions, enough evidence is available to enable one in most instances to roughly approximate the oil reserves. The greatest elasticity, however, will be given to the taxpayer in devising methods of esti- mating reserves so that proper allowances may be made in prac- tically every individual case that comes up for consideration, in order not to work undue hardship on the operators by arbitrary interpretations. The producing life of gushers yielding thousands of barrels of oil daily, obviously is controlled by different factors from those gov- erning the small pumping wells perhaps adjoining a big producer, and these and many other factors affecting the problem are ren- dered doubly obscure by the indefinite length of time throughout which the effect of the restricted land and marine transportation facilities will be felt. In view of the foregoing, the task of estimating the amount of . oil in any particular property will be left largely to the taxpayer controlling the tract and the Internal Revenue 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 evi- dence will be required by the Internal Revenue Bureau as that for properties 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 Fig. 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 rate of decline varies between wide limits; second, that there are i MANUAL FOR THE OIL AND GAS INDUSTRY 175 With this in mind we must be sure at the outset that (any estimates of probable depletion of the content of Mexican oil land, being based almost entirely on more or less plausible conjectures) any estimates of depletion of necessity presuppose a previous knowledge of the probable amount of oil underground in any par- ticular property, and although here again we are confronted with the lack of sufficient data on which to base accurate conclusions, enough evidence is available to enable one in most instances to roughly approximate the oil reserves. The greatest elasticity, however, will be given to the taxpayer in devising methods of esti- mating reserves so that proper allowances may be made in prac- tically every individual case that comes up for consideration, in order not to work undue hardship on the operators by arbitrary interpretations. The producing life of gushers yielding thousands of barrels of oil daily, obviously is controlled by different factors from those gov- erning the small pumping wells perhaps adjoining a big producer, and these and many other factors affecting the problem are ren- dered doubly obscure by the indefinite length of time throughout wliich the effect of the restricted land and marine transportation facilities will be felt. In view of the foregoing, the task of estimating the amount of . oil in any particular property will be left largely to the taxpayer controlling the tract and the Internal Revenue 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 evi- dence will be required by the Internal Revenue Bureau as that for properties 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 Fig. 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 rate of decline varies between wide limits; second, that there are 176 MANUAL FOR THE OIL AND GAS INDUSTRY occasional 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 Pennsylvania may decline very slowly over a period of many years. INDEX PAGE Abandonment of wells, pressure at 36 Accounts required, depletion 39 Adair district, Oklahoma 124 Adams County, Ind 112 Allegany County, N. Y 94 Allegheny County, Pa 97 Allen County, Ohio 112 Allocation between depletion and depreciation 16, 17 Allowance: For depletion 6, 19, 20, 31, 32, SO For depreciation 6, 13, 19 Property paid in and written off, etc 6 Reserve for depletion 6 Reserve for depreciation 6 Allowable deductions, cost of development 9 Amended returns, when required 17 Amortization: Definition of 18 Period 18 Property cost, returnable through 18 Redetermination of, requirements for 18 Appalachian region: Future production curves 99 General outline 92 Appraisal, curve method 86 Augusta district, Kansas, estimated future production 121 Avant-Ramona district, Oklahoma, estimated future production 126 Average decline curve 81 Bartlesville-Dewey, Hogshooter district, Oklahoma, estimated future pro- duction 122, 123 Basis : Of depletion deduction 21 Of discovery, revaluation of properties on 43, 44 For deductions 5 Bath County, Ky 104 177 178 INDEX PAGE Belmont County, Ohio 101 Belridge field, California 154 Berea sand, Ohio 101 Berea sand, West Virginia 100 Bird Creek-Skiatook district, Oklahoma 127, 128 Birds Flatrock pool, Illinois 114 Blackford County, Ind 112 Blackwell district, Oklahoma 133 Bona fide sale: of mines, etc 3, 4 Schedule for proof of 62 Boyle's law 31 Bradford sand, Pennsylvania 95 Buena Vista Hills, California 152 Buildings, depreciation of 71 Burkburnett field, Texas 136 Butler County, Pa 91 Caddo oil field 137 California oil fields 146 Capital, charges to 46 Capital recoverable through depletion allowance 20 Capital sum, illustration of 7 Capital sum and invested capital, depletion allowance, illustration of effect on 20 Capital sum returnable through depreciation allowance 15 Carlyle pool, Illinois 113 Casing-head gas contracts, tangible assets 46 Cattaraugus County, N. Y 94 Charges to — Depletion 90 Expenses 46 Claims, five-year limit for filing 12 Clark County, 111 113 Cleveland district, Oklahoma 126 Clinton County, 111 113 Clinton sand, Hocking and Wayne Counties, Ohio 103 Closed-pressure method : Corrections and refinements 32 For estimating depletion 32 of gauging 34 Readings to be recorded 35 Season for testing wells 35 Significant details 37 Closing account, depreciation 16 Coalinga East Side field, California 158 Coalinga West Side field, California 157 INDEX 179 PAOE Combined holdings of — Gas properties, depletion allowance, computation of 39 Oil properties, depletion allowance, conii)utation of 38 Computations of allowance for depletion of — Gas wells 29 Oil wells 27 Computation of depreciation allowances 15 Computation of: Surtax 2 Table of 2 Concrete example, depletion of gas 35 Corrections and refinements, closed pressure method 32 Corsicana field, Texas 134 Cost of deposits, determination of 23 Cost of property as of any specified date, schedule for ascertaining 47 Crawford County, 111 114 Cumberland County, 111 114 Curve : Average decline 81 Decline, symmetrical character 82 Production, definition of 81 Curves and tables, estimated future production 92 Cushing district, Oklahoma 129 Damages paid, deductible 12 Decline curves 82 Decline in open flow capacity, gas 30 Deductible as expenses, development cost, or charged to capital 10 Deductible, damages paid 12 Deduction of charges, time for, on books required 11 Deductions allowable: Bonuses to employees 11 Depletion 18 Depreciation 13 For personal services 11 Individuals 11 Return on accrued basis 11 Definitions : Amortization 18 Depletion 18 Depreciation 13 Expenses 10 Fair market value 24 Gross income 5 Net income 5 Physical property 9 Proven oil land 91 180 INDEX PAoa Definitions — Continued. Unit cost 28 Dehydrators, depreciation of 69 Dennison pool, Illinois 115 Depletion : Account required 39 Account separate from depreciation 40 Allowance for 6 Capital recoverable through, owner 20 Computation of — For combined holdings of gas properties 39 For combined holdings of oil properties 38 Concrete example of 31 Gas formula 36 Illustration of effect on capital sum and invested capital 21 Mexican fields 174 Apportionment among various sands 34 Apportionment of deductions between lessor and lessee . 22, 23, 24, 28, 29 Basis of deductions 19 For performance record 30 Charges corrected 90 Definition of 18 For years prior to 1916 17 Gas, additional indications of 31 Lessee entitled to 20 Of gas wells, computations of allowance for 29, 30 Of gas, concrete example 35 Of oil wells, computation of allowance for 29 Of oil or gas claimed, detailed statement to be attached 41 Of oil and gas wells 19 Past years not allowed 47 Reserve distribution from 40 Reserve for 6 Depreciable property 14 Depreciation : Accounts required 39 Allowance 6, 13 Capital sum returnable through 15 Computation of 15 Deductions on books required 16 Reserve 16 Buildings 17 Closing account 16 Computation of 15 Creditable to reserve 13 Definition of 13 Dehydrators 69 INDEX 181 PAOB Depreciation — Continued. Drilling equipment 68 Electric equipment 70 For years prior to 1916 17 Improvements 17 Intangible property 14 Machine shop 71 Personal effects not deductible 15 Pipe lines 71, 72 Rates, gas pipe lines 72 Refineries 73 Reserve distribution from 40 Schedule 62 Table, rate 78 Tank cars 72, 76 Tanks 70 Tools 70 Transportation equipment 70 Water plants 70 Well equipment 68 , De Soto field, Louisiana 140 Details concerning mai)s 42 Determination of — - Cost of deposits 23 Quantity of oil 25 Unit cost 27 Value — Direct methods 56 Fair market 23 Indirect methods 58 Development costs: Deductible as expense or chargeable to cajiital 9 Inclusions, allowable deductions 9, 10 Direct methods of determining value 56 Discovery : Proof of 43 Schedule for proving principal valae, demonstrated 65 Distributing stations 76 Dividend, liquidating 40 Dorseyville pool, Pennsylvania 97 Drilling e(juipmcnt, depreciation of 68 Economic limit of production 81 Eldorado district, Kansas 120 Electra field, Texas 135 Electric eriuipnumt, dci)reciation 70 Elk Basin field, Wyoming , 145 182 INDEX PAGE Equal expectations, law of 88 Equipment {see also physical property) 9 Estill County, Ky 106 Estimate required of recoverable oil 26, 27 Estimated future recovery 85-91 Estimating depletion, closed-pressure method for gas 31 Excess-profits tax and war profits 4 Expenses : Charges to 46 Definition of 10 Improvements and betterments not deductible as 10 Repairs and replacements 10 Fair market value, definition of 25 Fellows area, Midwayfield, Calif 149 Fictitious price not permissible 23 Fifth sand, Pennsylvania 97 Filling stations 75 Five-year limit for filing claims 12 Floyd County, Ky 105 Foreword iii, iv Formula, depletion allowance, gas 36 Fullerton oil field, La Habra group, California 164 Future production, method of estimating 80 Future production curves: Appalachian district 99 California oil fields 149, 166 Illinois-Indiana field 113 Lima-Indiana field 110 Mid-Continent district 122, 133 Northern Louisiana fields 136 Rocky Mountain fields 141 Future production curves and tables 92 Garber district, Oklahoma 132 Garfield County, Okla 132 Gas: Amount of concrete example 31 Decline curves 175 Decline in open-flow capacity 30 Natural 76 Pipe line, depreciation rate 71 Pore-space method for estimating supply of 30 Pressure, observation of 31 Gasoline plants, natural gas 77 Gibson County, Ind 116 Glenn ]nm\, ( )klahoma 128 INDEX 183 PAGE Gore pool, Ohio 103 Gordon sand in Wetzel County, W. Va 102 Grant County, Ind 113 Grass Creek, Wyo 144 Gratuities not deductible 11 Gross income definition of 5 Hancock County, Ohio Ill Harrison County, W. Va 99 Healdton district, Oklahoma 132 Hocking County, Ohio 103 Hot Springs County, Wyo 144 Hundred Foot sand, Pennsylvania 96 Huntington County, lad 113 Illinois-Indiana field future production curve 107 Improvements and betterments not deductible as expense 10 Improvements, depreciation of 17 Indeterminate losses 13 Indications of depletion, gas 31 Indirect methods of determining value 58 Individual normal income tax of 1 Individual, surtax of 1 Insurance companies, deductions special 5 Intangible property, depreciation of 14 Invested capital 7 Irvine pool, Kentucky, estimated future production 106 Jefferson County, Ohio 101 Keener sand, Ohio 102 Kirkwood pool, Illinois 115 Law of averages 87 Law of equal expectations 88 Lawrence County, 111 115 Lease, valuation of fee under 25 Lessee and lessor, apportionment of deductions between 22 Lessee: Capital recoverable through depletion allowance 20 Entitled to depletion 20 Lima-Indiana district 94 Lima-Indiana field, future production curves 107 Limit of production, economic 81 Limits on surtax and war excess-profits tax in case of sale 3 Lincoln County, W. Va 100 Liquidating dividend 40 Losses deductible 12 184 INDEX PAGE Losses : Determinate 13 Not deductible 13 Lost Hills field, California, estimated future production 155 Lucas County, Ohio, estimated future production Ill Machine shop, depreciation of 71 Maps: Details concerning 42 To be submitted 42 Maricopa Flat area. Sunset oil field, California 151 Marion County, Tex 139 Marion County, 111 113 McDonald pool, Pennsjdvania 97 McDonough County, 111 115 McKean County, Pa 94 McKittrick field, California 153 Method, appraisal curve 86 Method of — Amorization 18 Computing depletion, gas 30 Estimating future production 83, 85 Estimating recoverable oil reserves 26, 83 Gauging gas, closed pressure 31 Mercer County, Ohio 112 Mexican fields, allowances for 174 Mexican oil fields 173 Storage capacities 174 Transportation facilities 174 Mid-Continent district, future production curves 117 Midway-Sunset field, California 148 Monroe County, Ohio 101, 102 Mooringsport pool, Louisiana 139 Muskogee-Boynton district, Oklahoma 130 Natural gas 76 Gasoline plants 77 Unit cost 32 Neodesha district, Kansas 121, 122 Net income, definition 5 New Straitsville pool, Ohio 103 Normal income tax of individual 1 Northern Louisiana fields, future production curves 136 Nowata district, Oklahoma 123 Oil and gas wells, depletion of 18 Okmulgee district, Oklahoma 131 INDEX 185 PAGE Olinda field, California 165 Osage County, Okla 125 Ottawa County, Ohio Ill Performance record, basis for gas depletion 30 Period, amortization 18 Perry County, Ohio 103 Personal effects, depreciation not deductible 14 Personal services, compensation for 11 Physical property, definition of 9 Pike County, Ind 116 Pine Island pool, Louisiana 130 Pipe lines, depreciation of 71, 72 Plymouth pool, Illinois 115 Pore-space method for estimating supply of gas 30 Pressure at abandonment of wells 36 Pressure, observation of gas 31 Production curves, definition of 81 Production curves, plotted 84 Production, estimates of 148 Production oil zone 147 Proof required in case of sale of mineral deposits 4 Property, cost of, allowable deductions 9 Property, cost of, inclusions 9 Property cost returnable through amortization 18 Property, depreciable 14 Property, depreciation of intangible 14 Property, nondepreciable 15 Property paid in and written off: Reserve for depletion 6, 7 Reserve for depreciation 6, 7 Proven oil land, definition of 91 Quantity of oil, determination of 25 Readings, closed-pressure, significant details 38 To be recorded 37 Recoverable oil, estimate required 26 Recoverable oil reserves, methods of estimating 26, 80, 83 Redetermination of amortization 18 Red River field, Louisiana 139, 140 Refineries, depreciation of 73, 74 Repairs and replacements charged as exjjense 10 Requirements for amortization 18 Reserve: Distribution from depreciation 40 Depreciation creditable to 13 186 INDEX PAGE Return on accrued basis, deductions 11 Revaluation of properties on basis of discovery 43, 44 Revaluation of property, not permissible 25 Revaluation of properties, ruling on 43 Revaluation within 30 days of discovery, allowable 19 Roane County, W. Va 99 Robinson pool, Illinois 114 Rocky Mountain fields, future production curves 141 Sale, limits on surtax and war-excess profits tax in case of 3 Sale of capital assets, schedule for computation of profits or loss from ... 64 Mineral deposits, surtax on 3 Sale, schedule for proof of 62 Sale of mineral deposits, proof required in case of 4 Sale of mines, etc., bona fide 3, 4 Sales or marketing equipment 75 Salt Creek field, Wyoming 143 Salt Creek field, first Wall Creek sand 144 Salt Lake field, California 161 Sandoval pool, Illinois 113 Sandusky County, Ohio Ill San Joaquin Valley, Calif 146 Santa Maria field, California. 159 Schedule for ascertaining cost of property 47 Computation of profit or loss from sale of capital assets 64 Depletion 61 Depreciation 62 Proof of bona fide sale 62 Proving principal value demonstrated by discovery 65 Proof of discovery 59 Valuation of property 53 Season of testing wells, closed pressure 35 Seneca County, Ohio Ill Shinnston pool. West Virginia 99 Siggins pool, Illinois 114 Speedily sand, Pennsylvania 95 St. Marys pool, Ohio 102 Statement to be attached, depletion of oil or gas claimed 41 Sullivan pool, Indiana 116 Surplus, allowance for — Depletion 6, 7 Depreciation 6, 7 Surplus and undivided profits 6, 7 Surtax : Computation of 2 Table of 2 INDEX 187 PAGE Surtax — Continued. On sale of mineral deposits, limits of 3 Of individual 1 Table: Depreciation rates, marketing equipment 75 Estimated future production: Adair district, Oklahoma 125 Adams County, Ind 112 Allen County, Ohio 112 Augusta district, Kansas 121 Avant-Ramona district, Oklahoma 126 Bartlesville-Dewey, Hosghooter district, Oklahoma 123 Batson 171 Belridge field, California 155 Berea sand, West Virginia and Ohio 101 Big Injun sand. West Virginia '. 100 Bird Creek-Skiatook district, Oklahoma 127 Birds-Flatrock pool, Illinois 114 Blackford County, Ind 112 Blackwell district, Oklahoma 133 Bradford sand, Pennsylvania 95 Buena Vista hills, California 153 Burkburnett field, Texas 136 Carlyle pool, Illinois 113 Clark County, 111 113 Cleveland district, Oklahoma 127 Clinton County, 111 113 CUnton sand, Hocking and Wayne Counties, Ohio 104 Coalinga, East Side field, California 158 Coalinga, West Side field, California 157 Corsicana field, Texas 134 Crawford County, 111 114 Cumberland County, 111 114 Gushing district, Oklahoma 129 Dennison pool, Illinois 115 De Soto field, Louisiana 140 Dorseyville pool, Pennsylvania 97 Edgcrly 172 Eldorado district, Kansas 120 Electra field, Texas 135 Elk Basin field, Wyoming 145 Evangeline 173 Fellows area, California 150 Fifth sand, Pennsylvania 97 Floyd County, Ky 105 Fullerton oil field, La Habra group 165 188 INDEX PA08 Table — Continued . Estimated future production — Continued. Garber district, Oklahoma 132 Gibson County, Ind 116 Glenn pool, Oklahoma 128 Goose Creek 169 Gordon sand in Wetzel County, W. Va 101 Gordon sand in Greene County, Pa 98 Gordon sand in Allegheny County, Pa 98 Gore pool, Ohio 103 Grant County, Ind 113 Grass Creek, Wyo 144 Hancock County, Ohio 112 Healdton district, Oklahoma 133 Humble Field 168 Himdred foot sand, Pennsylvania 96 Huntington County, Ind 113 Irvine pool, Kentucky 106 Jackson Ridge pool, Ohio 102 Johnson pool, Illinois 114 Kern River field, California 159 Kirkwood pool, Illinois 115 Lawrence County, III 115 Lost Hills field, California 156 Lucas County, Ohio Ill Maricopa Flat area. Sunset oil field, California 152 Marion County, 111 113 Marion County, Tex 139 McDonough County, 111 115 Mclvittrick field, California 154 Mercer County, Ohio 112 Mooringsport pool, Louisiana 139 Muskogee-Boynton district, Oklahoma 130 Neodesha district, Kansas 122 Nowata district, Oklahoma 124 Okesa district, Oklahoma 125 Okmulgee district, Oklahoma 131 Olinda field, California . 166 Pike County, Ind 116 Pine Island pool, Louisiana 140 Plymouth pool, Illinois 115 Ragland pool, Kentucky 104 Red River field, Louisiana 140 Robinson pool, Illinois 114 Salt Creek field, first Wall Creek sand, A\'yoming 144 Salt Lake field, California 162 Sandoval pool, Illinois 113 INDEX 189 PAQE Table — Continued. Estimated future production — Continued. Sandusky County, Ohio Ill Santa Maria field, California 160 Saratoga, Rio Bravo 170 Seneca County, Ohio Ill Shinnston pool, West Virginia 99 Siggins pool, Illinois 114 Sour Lake 171 Speechly sand, Pennsylvania 95 St. Marys pool, Ohio 102 Sullivan County, Ind 116 Twenty-five Area, California 151 Upper Lawrence County, 111 115 Van Wert County, Ohio 102 Ventura County field, California 161 Vinton 172 Vivian pool, Louisiana 139 Wayne County, Ky 106 Wells County, Ind 112 West Coyote field, California 164 Westfield pool, Illinois 113 Whittier field, California 163 Wood County, Ohio Ill Tampico-Tuxpam region, Mexico 173 Tank cars, depreciation of 72 Tanks, depreciation of 69 Tax on corporations for 1918 4 Taxes, deductible 12 Taxes, not deductible 13 Tehuantepec-Tabasco region, Mexico 173 Time for deduction of charges 11 Tools, depreciation of 70 Transportation equipment, depreciation of 70 Ultimate production 87 Underground reserves of oil recoverable, estimate of 80 Unit cost: Definition of 28 Determination of • 28 Natural gas 32 Upper Lawrence County, 111 115 Valuation of: Fee under lease 25 Property, schedule for 53 Valuation, ruling regarding 25 190 INDEX PAQB Van Wert County, Ohio 112 Various sands, depletion, apportionment among 34 Ventura County field, California 160 Vivian pool, Louisiana 139 War-profits and excess-profits tax 4 Washington County, Ohio 102 Washington County, Okla 122, 126 Washington County, Pa 97 Wayne County, Ky 105 Wayne County, Ohio 103 Well equipment, depreciation of 68 Wells County, Ind 112 West Coyote field, California 163 Westfield pool, Illinois 113 Wetzel County, W. Va 101 Whittier field, California 162 Wood County, Ohio Ill my 2 5 1974 14 DAY USE __ KETUKN TO DESK FROM WHICH BORKOWED EARTH SCIENCES LIBRARY TEL: 642-2997 LD 21-32w-3,'74 (R70578l0)476 — A-3^ General Library . University of California Berkeley / A A^ "■■Bf