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Prorationing and its effect on investment in the Canadian oil industry Lee, William Randolph 1967

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PROBATIONING AND ITS EFFECT ON INVESTMENT IN THE CANADIAN OIL INDUSTRY by WILLIAM RANDOLPH LEE B.Sc, University of Alberta, 1957 A THESIS SUBMITTED IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE DEGREE OF MASTER OF ARTS in the Department of ECONOMICS We accept this thesis as conforming to the required standard. THE UNIVERSITY OF BRITISH COLUMBIA September, 1967 In p r e s e n t i n g t h i s t h e s i s i n p a r t i a l f u l f i l m e n t o f t h e r e q u i r e m e n t s f o r an a d v a n c e d d e g r e e at t h e U n i v e r s i t y o f B r i t i s h C o l u m b i a , I a g r e e t h a t the L i b r a r y s h a l l make i t f r e e l y a v a i l a b l e f o r r e f e r e n c e and s t u d y . I f u r t h e r a g r e e t h a t p e r m i s s i o n f o r e x t e n s i v e c o p y i n g o f t h i s t h e s i s f o r s c h o l a r l y p u r p o s e s may be g r a n t e d by the Head o f my Department o r by h i s r e p r e s e n -t a t i v e s . I t i s u n d e r s t o o d t h a t c o p y i n g o r p u b l i c a t i o n o f t h i s t h e s i s f o r f i n a n c i a l g a i n s h a l l not be a l l o w e d w i t h o u t my w r i t t e n p e r m i s s i o n . Department o f C O 0 < £ > The U n i v e r s i t y o f B r i t i s h C o l u m b i a V a n c o u v e r 8, Canada Date - i -ABSTRACT Prorationing is sometimes implemented when the producing capacity of an area exceeds the demand for that output at a price which many producers feel to be "fair" -when this situation occurs the price of course comes under pressure as producers compete with one another to sell their o i l . It is in order to avoid such a possibility that operators are sometimes successful in persuading the government having jurisdiction to assume the responsibility of setting up and policing a prorationing plan. Under such a scheme the total demand for crude o i l from the area, at the desired price, is alloted among a l l the producers of the area on a basis related to some measure of each producer's capacity - no producer has any Incentive to lower his price as he would not be awarded any larger share of the market for so doing. In simple words then the name of the game Is price fixing. Since December 1950 such a scheme for "prorationing production to market demand" has been in force in the province of Alberta and. is administered by a board created by the provincial government. This practice of prorationing has had a great influence on the manner in which the Canadian oi l industry has developed, not only in the province of Alberta (which is by far the largest producer of crude) but in the other o i l producing provinces as well (these being mainly B.C., Sask., and Man.). It has in fact encouraged large amounts of excess expenditure to take place in the - i i -development of Canada's crude o i l resource. Prorationing has encouraged this overexpenditure in two ways - first through the maintenance of an artifically high price for crude o i l which has encouraged the develop-ment of high cost sources at the expense of already exist-ing low cost ones that must as a result suffer "shut-in" capacity, and secondly as a consequence of the regulations governing the method by which the demand is apportioned which has led to the overdrilling of o i l fields. A third cause of overexpenditure have been field regulations outside of the prorationing plan such as provincial legislation dealing with minimum allowed well spacing, the manner in which maximum allowable rates of production for wells have been calculated, and the manner in which lease rights are allowed to be held. Our estimate is that poor field regulations, both inside and outside of prorationing, have led to excess expenditures of some $730 million in the period 1947 to 1965 inclusive. Overexpenditure due to prorationing itself has amounted to some $1,0.00 million. Extensive amendments to the prorationing regulations in 1964 improved these markedly and largely removed them as a source of future waste. Prorationing itself however and the regulations governing the holding of leases remain, and so long as they do serious overexpenditures will continue to be made. - i i i -TABLE OP CONTENTS Chapter Page I The Growth of the Canadian Oil Industry 6 II The Prorationing Regulations Part I : A Description 23 Part I I : A Criticism 31 III The Determination of Overinvestment Part I: Overinvestment Due to Poor Field Regulations 46 Part II: Overinvestment Due to Prorationing Itself 62 IV The Significance of the Overinvestment 90 V Conclusions and Recommendations 107 Bibliography 112 Appendixes I Disposition of Sub-Surface Rights in Western Canada 115 II Growth of Canadian Oil Reserves 116 by Major Fields - to December 1950 III Growth of Canadian Oil Reserves by Major Fields - December 1950 to December 1966 117 IV The Alberta Maximum Permissive Rate (MPR) Formula 121 V Excess I n f i l l Wells Drilled in Western Canada 124 VI Average Depth of the Excess Development Wells 133 VII Productive Oil Development Wells Drilled in Western Canada - 1947 to 1965 135 VIII Actual Crude Oil Production - Western Canada Light & Medium Crude Categories 136 IX Industry Rate of Return l 4 l ACKNOWLEDGEMENTS I should like to express sincere thanks to Professor P. G. Bradley whose help and criticism are responsible for much of what is right in this thesis. For whatever may be wrong I have only myself to thank. My biggest debt is to my wife who for two years has somehow managed to work, hold my hand, do my typing, and keep smiling a l l at the same time. I. couldn't have done without her help. INTRODUCTION The purpose of this paper is to calculate the amount of overinvestment that has taken place in the development of Canada's o i l industry, due primarily to the institution of "prorationing production to market demand", but also due to such other regulations (prescribed by the respective provincial governments) as those governing well spacing, maximum permissible rates of production from wells, and the disposition of "leases". Further we will study the signific-ance of this amount of overinvestment in affecting the price of Canadian crude oil and postulate what other markets Canada would have been able to secure through a lower price had this excess expenditure not taken place. We will make suggestions as to what future policies governing the o i l industry should be in order to halt the continuation of overinvestment. What is Prorationing? Prorationing (or prorating) in o i l industry parlance means the distribution of the "demand" for o i l among the o i l producers of an area proportional to some measure of each producers share of the total producing capacity of the area. It is made necessary, when, at a price pre-determined by the o i l producers, the supply of oil from the area in question exceeds the demand for that quantity. Rather than allowing the price to drop, hence equating supply and demand, the price is held at the desired level by restricting supply. This then means that a formula must be found to enable the determination of quotas which must be applied to each producer so that "demand" is not exceeded and so that i t is equitably distributed among the producers. This setting of quotas is best done, of course, by an impartial body and typically devolves to a government agency with the necessary powers to enforce the quotas thus set. How Does Prorationing Lead to Over-Investment? Any prorationing scheme promotes overinvestment in d r i l l -ing, development, and production costs in that its purpose is to maintain a higher price for o i l than would otherwise prevail. This higher price encourages the development of higher cost sources which then produce at the expense of lower cost ones which are given quotas below their most efficient rates. In addition a prorationing scheme may lead to even further overinvestment i f its "formula" for sharing the "demand" is such that i t encourages closer drilling than necessary to adequately develop an o i l pool. Our aim in what follows is to look at prorationing as i t has existed in Canada and try to determine how much over-investment has taken place due to each of the above causes -i.e. how much has occured 1. due to the fact of prorationing itself, and 2. due to regulations within the scheme that have encouraged over drilling.(Also under this latter category we will consider the amount of over-investment - in the form of overdrilling - encouraged by field regulations other than those connected with the prorationing scheme). - 3 -The Outline Chapter I will sketch the growth of the oil industry in Canada and the development of the "ground rules" under which i t operates. Also described will be the forces which developed leading to the establishment and to the con-tinuance of the prorationing' plan. In Chapter II, Part I, we will outline in some detail the prorationing regulations as they were in the beginning and as they were amended over time. Part II of the chapter will be a criticism of these regulations. Chapter III will be concerned with the determination of the amount of over-investment which has taken place. Part I will be a calculation of the over-investment caused by poor field regulations, both within and outside the prorationing scheme, which have led to the overdose drilling of fields. Part II will consider excess expenditure encouraged by the fact of prorationing itself which has resulted in. the develop-ment of high cost fields. In Chapter IV we will calculate how much lower the price of crude could have been had the overinvestment calculated in Chapter III not taken place. This will be followed by a consideration of what this lower price might have meant in terms of greater markets for Canadian o i l , both domestic and foreign. Chapter V will be the concluding one and will offer recommendations suggesting what future government policies should be so as to prevent the continuance of this economic waste. ,- 4 -CHAPTER I THE GROWTH OP THE CANADIAN OIL INDUSTRY Virtually a l l of Canada's productive capacity of o i l is, and has been, located in her four Western provinces, with Alberta being by far the richest source. Before considering the actual growth of the industry in terms of o i l discoveries we must fi r s t consider a couple of related aspects which have played an important part in the determination of how this growth took place. It is necessary to look first at the pattern of mineral resource ownership in Canada, and second to study the methods and procedures by which o i l companies secure access to areas in which they are interested for purposes of exploration and o i l production. The Pattern of Mineral Resource Ownership The Canadian situation in this regard results from the legal principle that a l l land was originally owned, by the Crown (British). In the year 1670 the Hudson's Bay Co. obtained from King Charles II a land grant which consisted of a l l lands drained by streams flowing into the Hudson's Bay - this grant included a l l surface and mineral rights. The area involved took in a large part of what is now Western Canada's o i l producing area. Shortly after Confederation, in 1867, Canada purchased most of these lands, including mineral rights, from the Company though leaving i t , as a rule, with sections 8 and 26 in every township in the surveyed areas of Western Canada, and also with certain other areas such as around its trading posts. Also, with Confederation, Canada acquired surface and subsurface rights from the British Crown with respect of a l l the other lands in the Dominion. Beginning in the l 8 8 0 ' s Canada made grants of land, including both surface and subsurface rights, to the C.P.R. and other railroad companies as an encouragement to them to build their "roads". Grants to the C.P.R. alone amounted to 1 some 23 million acres in the Prairie provinces. Though the majority of these surface rights have been disposed of, the C.P.R. has retained the mineral rights. A small percentage of mineral rights is also held in the Western provinces by individual freeholders. Before 1887 and as settlers made their way into these areas they were granted homestead rights (mineral and surface) by the Federal govern-ment. After I887 only surface rights were granted. Much of Manitoba was settled before 1887 and consequently there is a high proportion of freehold mineral rights in that province. In Saskatchewan the main area homesteaded before 1887 was the southeast corner which is now her important o i l producing area. Alberta and the Peace River "block" of British Columbia were settled last so that freehold areas here are relatively small. British Columbia, which became a province in I87I, obtained sovereignty to its mineral rights from the Federal government at that time, and virtually a l l the mineral rights in B.C. are held by the province. In 1930 the Prairie provinces received a l l the mineral rights within their borders from the Federal Government with the exception of those mentioned above and small areas within - 6 -the boundaries of Indian Reservations and military establish-ments . The Federal government holds nearly a l l subsurface rights 2 in the Yukon and Northwest Territories. In summary, then, each provincial government has title to the bulk of its mineral resources and is responsible for legislation, i f any is felt necessary, with respect to the development of a l l mineral resources, whether i t holds title or not. In the realm of o i l and gas each of the four Western provinces in fact does feel that a considerable degree of control must be maintained over the development of these resources. These controls are administered in Alberta by an independent board (the Oil and Gas Conservation Board), and in the other provinces by the Minister of Mines acting on the advice of a Board. The Method of Land Acquisition by Oil Companies We will now describe the procedure whereby o i l companies receive rights to areas of land for the purposes of explora-tion and production. Practices vary from province to province 3 but the description that follows is fairly typical. "Exploratory permits" entitling the holder to exclusive rights to explore for petroleum and natural gas must be obtained, from the Board or government Department responsible, by any party who wishes to explore for o i l . These permits are issued for areas not exceeding 100,000 acres, and whose length must not be more than three times their breadth. - 7 -Exploratory wells may be drilled under such a permit, but the holder has no right to begin production until a "lease" has been applied for and granted. The exploratory permits issued may, and in many cases will, cover an area which includes freehold as well as provincial lands, in the sense of mineral rights ownership. If the holder of a permit is satisfied that his area is a good one he may, subject to the restrictions below, convert i t to "lease" at any time - i f he discovers petroleum in commercial quantities he must do so three months from date of the discovery. The holder of an exploratory permit is not allowed to convert more than 50$ of it's "Crown" area into lease - also there are restrictions stipulating how these lease areas may be distributed within the permit area. In Alberta, a "Crown" lease may not exceed a rectangular area of 4 miles by 2 miles, or a square 3 miles by 3 miles. Not more than half of any township (a township being 36 sections or 23,040 acres) may be converted to lease and leased areas may not adjoin except that they may touch at the corners. Rights to freehold acreage are directly negotiable with the owner of same and there are no restrictions as to who may buy. The portion of the government's land in an exploratory permit which is not taken up by the i n i t i a l operator reverts to the province and becomes what is known as "Crown Reserve". Leases in this "Crown Reserve" are then "sold" by the province to interested operators who bid for them by sealed tender. In successful areas - i.e. where the i n i t i a l operator has - 8 -"brought in" one or more good wells - the lease rights are offered in small parcels, usually one quarter section in size 4 5 or a "spacing unit" , whichever is the larger. One further note in this connection - the provincial authorities in every case exercise considerable control over the drilling of wells. A licence must be obtained before a well is commenced. In this manner the spacing of wells - at least the minimum spacing - is strictly regulated. The Growth of the Industry Let us now turn to consider the stages in Canada's development as an o i l producer of considerable stature. We shall look at this development in terms of o i l discoveries and the growth of markets, with attention paid to the forces which resulted in the establishment of prorationing. The fi r s t important discovery insofar as crude o i l was concerned was near Turner Valley, in Alberta, approximately 35 miles southwest of Calgary - although at first this field was of primary importance as a producer of natural gas. The field was discovered in 1914 but few wells were drilled in the first 10 years of its' l i f e due to a lack of markets for the gas.^ I n 1924 an extremely prolific producer was found (in a new formation) whose importance to the operators was great not because of the gas, but for the naphtha(a very high grade crude) which accompanied i t . From the time of that discovery to 1936 more than 200 wells were drilled, principally to recover 7 the naptha.1 Very large quantities of natural gas from the g field were "flared" during this period. - 9 -In 1936 Turner Valley became a bona fide o i l producer with a deep well (approximately 7,000') strike in the field's west filank. This discovery led to the realization, by govern-ment authorities at least, that further indiscriminate pro-duction of the gas cap, as had been taking place, could not be tolerated, as i t would seriously reduce the ultimate recovery of the newly found crude reserves of the field. The government discussed the problem with representatives from the industry in an attempt to find a scheme for shutting in the gas cap, which would be satisfactory to both producers and plant operators. "It soon became evident that such an agree-ment would not be completed and that proper conservation could 119 only be achieved through compulsory legislation. This then led to the passage of the Alberta Oil and Gas Conservation Act in 1938 under whose authority the Petroleum and Natural Gas Conservation Board was appointed."^ (Later changed in name to the Oil and Gas Conservation Board, (O.G.C.B.)). Following the 1936 discovery well much drilling activity took place. Between 1936 and 194-1 nearly 200 wells were drilled 11 of which only half a dozen were dry, Eventually the total number of producers exceeded 300. The field attained, its peak output, in 1943, of 9.7 million barrels (approximately 26,500 barrels per day (b/d)) which was almost 95$ of the total 12 Canadian output at that time. The early years of Turner Valley as an oil producer saw the first application of prorationing. The need for i t grew from the rapid increase of crude production and the lack of suffic-ient refinery capacity to handle i t . Imperial Oil, who was the - 10 -major refiner in the area (and who, through its subsidiary, The Royalite Oil Co., was also the major producer in the field), attempted to handle the problem by setting up a system of quotas which they would purchase each month from each well. Not surprisingly this scheme met with less than the f u l l approval of the independent producers. As a result of the dis-satisfaction with this system of "buyers1' quotas" the Oil and Gas Conservation Board in 1938 took over the responsibility of setting the well allowables. Prorationing at this time did not last for long however, as the outbreak of the Second World War led to a rapid, growth of demand and solved the problems of over production. The Board continued to operate, however, in its "conservation" capacity regulating the maximum allowable rates of production for o i l and gas. The next big step in the country's o i l development (the step in fact now recognized as the one that put Canada on the road to becoming an important o i l producer) came in 19^7 with the discovery, by Imperial Oil, of the Leduc field about 15 miles southwest of Edmonton. Although there had been various crude o i l "strikes" after Turner Valley and before this one (mostly in Alberta), they had been of small importance. Leduc however was a major find and spurred exploration and drilling activity which in turn led to a series of very important discoveries in the years that followed. By the end of 1948 Leduc had overtaken Turner Valley as the most productive 1 field with 175 wells and production of approximately 22,000 b/d - 11 -(Turner V a l l e y production at the end of 1948 was about 13,400 b/d). Utimately the number of w e l l s capable of production i n the Leduc f i e l d reached 1,278 ( i n 1954). In mid 1948 " I m p e r i a l " s t r u c k again, t h i s time 40 miles northeast of Edmonton i n what was to prove to be 14 an even b e t t e r f i e l d than Leduc. This was Redwater. With both Leduc and Redwater being developed q u i c k l y 1949 saw the appearance once again of excess productive c a p a c i t y . At the end of 1949 productive c a p a c i t y , from a l l f i e l d s , was approximately 88,000 b/d, whereas demand, at the p r i c e s posted by the r e f i n e r s , was i n the order of 51,000 b/d. This r e s u l t e d , then, i n a "shut i n " c a p a c i t y of roughly 37,000 b/d. 1^ In 1950 the excess c a p a c i t y problem worsened markedly, due p a r t i c u l a r l y to the r a p i d development of the Redwater f i e l d coupled w i t h the f a c t that the P r a i r i e market area, which was the only market area that the o i l could c o m p e t i t i v e l y reach at that time, was j u s t not b i g enough. Also 1950 saw more w e l l s d r i l l e d i n Leduc, and the "coming on stream" of other f i e l d s that had been discovered i n 1949, the most important being Joarcam and Golden Spike. At the end. of 1950 t o t a l productive cap-a c i t y was i n the order of 184,000 b/d; demand was about 95,000 b/d."^ In other words approximately one-half of c a p a c i t y was s h u t - i n . In the e a r l y stages of t h i s over c a p a c i t y s i t u a t i o n the o i l i n d u s t r y again r e v e r t e d to the p r a c t i c e f i r s t used i n Turner V a l l e y whereby the purchasing companies a l l o t e d quotas - 12 -that they would purchase each month from each producer. And again, probably due in no small part to the fact that the major purchasers were also major producers, there was dissatisfaction with this procedure, so that in mid 1950 the Oil and Gas Conservation Board was requested, by many of the producers, to once more assume the responsibility of "prorationing production to market demand." In November 1950 the Board announced its decision to proration production, starting December 1, 1950, and revealed the "formula" under 17 which the prorationing would be done. Prom that time to the present prorationing has been in effect in Alberta. Although the'market" for crude has in-creased, very greatly over this period - from the 95,000 b/d at 18 the end of 1950 to some 800,000 b/d at the end of 1965 -production capacity more than kept pace so that i t stood at 19 the end of 1965 at approximately 1,650,000 b/d . That is, s t i l l about one-half of the industry capacity is shut in. In Alberta, following Redwater, the discoveries came thick and fast. In the few years afterwards the big field names were: Joarcam and Golden Spike (19^9) , Penn-Big Valley (1950), Wizard Lake (1951), Bonnie Glen (1952), Sturgeon Lake (1953), and, the grand-daddy of them a l l insofar as reserves 20 were concerned, Pembina (195*0. In 1951 o i l became more than a one province show with the discovery of the Daly field in Manitoba. 1953 saw Saskatchewan 'make the scene" in a big way with the find, in the southeast corner of the province, of the Midale field; Manitoba also - 13 -struck again with the Virden field. British Columbia became a producer in 1955 with a major find at Boundary Lake, about 30 miles northeast of Port St. John. Since that time several discoveries have been made in this same area the most note-worthy being Peejay in 1959. Saskatchewan in the later '50's continued to have successes in its southeastern area with the finds of its Weyburn (1955), Steelman (1955), and Alameda (1956) fields. Alberta added greatly to its reserves through notable strikes at Swan Hills (1957), Virginia Hills (1957), and Judy Creek (1959), a l l of which were in an area 100 to 120 miles north-west of Edmonton. Though a l l provinces have shared in the "oi l pie" their slices have by no means been equal. Alberta is by far the largest source of o i l followed at some distance by Saskatchewan. British Columbia though not a large producer holds considerable promise of further finds, especially in its northeast corner. Manitoba on the other hand does not appear to be a promising area, has not had any discoveries of significance since the Virden find of 1953, and presently produces only a small portion of the Canadian output. As an indication of their "standings" following are their 21 1965 average daily production figures: British Columbia Alberta Saskatchewan Manitoba Total 37,000 b/d 510,000 b/d 240,000 b/d 13,000 b/d 800,000 b/d - 14 -In addition to this the amount of shut-in capacity in 22 Alberta was about 850,000 b/d. Alberta, i t will be noted, is the only province with shut-in capacity - the other three provinces operate their wells at the maximum permissible rates (M.P.R.'s) that 23 their Boards will allow. Alberta has been "nailed" into this unhappy position by fact of being the major producer and hence the one with most to lose i f "orderly market conditions" are not maintained. The other provinces take advantage of this, so to speak, by producing at capacity in the knowledge that Alberta will curtail production should demand f a l l , and increase production i f demand should rise -and this of course she must do being interested in the main-tenance of a stable price. As M. A. Adelman says "This is the classic dilemma of the largest producer in a cartel, who holds the umbrella for those nibbling away at its market 24 share." It must be remembered though that many of the producers operating in Alberta also have operations in the other areas so for them it?s a matter of "making up on the roundabouts what they lose on the swings". Having had a quick look at the growth of the productive potential of the industry we must now round out the picture by considering the development of Canada's o i l markets. As was indicated above i t became obvious in 19^9 that the Prairie market was too small in relation to the mounting reserves and potential output of the Alberta fields, so that new areas - 15 -and means of reaching them were considered. The most promising market appeared to be Ontario, largely of course because i t was a big one, but also because i t had refineries 25 with total capacities in the order of 100,000 b/d (in the Sarnia and Toronto areas) which at the time were being supplied with high cost crude from the Illinois and Mid-Continent areas of the U.S.A. The Alberta producers felt they could under-price these sources with l i t t l e sacrifice to their existing wellhead prices. The fact that Imperial Oil had the biggest refinery capacity in the area - 55,500 b/d at Sarnia - doubtless was also a significant factor in the decision. The decision was made to construct a pipeline to Superior, Wisconsin (at the head of Lake Superior) from which point the o i l would be shipped by freighter the remaining distance to Sarnia. The line was begun in 19^9 and completed in December 1950. It ran from the Edmonton area, southeastward to Regina, to Gretna on the Manitoba - U.S.A. border, and on to Superior, a total distance of 1,129 miles. The i n i t i a l capacity was 95,000 b/d to Regina and 70,000 b/d to Superior. This line was extended, through Wisconsin and Michigan to Sarnia in 1953 and then on to Toronto in 1957. The present capacity of this / 26 line, east of the Saskatchewan border, is 575,000 b/d . m addition to serving Ontario markets this line also supplies oi l to refineries in Minnesota, Wisconsin, and Michigan 27 (approx. 113,000 b/d in 1965). The pipe line is known as The Interprovincial Pipe Line, after the company of that name. - 16 -With the completion in 1950 of the first stage of "Interprovincial's" line, attention was turned to the West Coast. Although British Columbia's consumption at that time of 40,000 b/d was too small to justify the construction of a pipeline, there was a very attractive looking market area in the "Pacific'Northwest" region of the U.S.A., which added to B.C.'s certainly would support the investment. There was a problem however - lack of refinery capacity. Washington and Oregon requirements were met by tanker ship-ments of refined products from California. The outbreak of the Korean War created a critical o i l supply situation in the Pacific region and gave impetus to proposals to pipe Alberta crude westward. Agreements were reached between Canadian arid American o i l companies with respect to purchase arrangements and construction of refinery capacity in northern Washington State. As a result the Trans Mountain Pipeline was commenced in 1952 - originating near Edmonton - and completed in September 1953, with an i n i t i a l capacity of 150,000 b/d. The present 29 capacity is 250,000 b/d, crude now also being fed into the line from B.C.'s northern fields through the "Western Pacific" pipeline. In 1965 approximately 142,000 b/d were exported to 30 Washington refineries. These two pipelines s t i l l afford Canadian o i l its major access to markets outside the Prairie region. The total of 31 crude o i l and equivalent exports to the U.S.A. in 1965 averaged nearly 300,000 b/d, The balance of Canadian production, - 17 -some 620,000 b/d, was consumed in the Western Canada and Ontario regions. Canada's Eastern regions, including Quebec province and the Maritimes, are supplied with Venezuelan and Middle East o i l , a total amount in 1965 of roughly 400,000 b/d. With this brief look at the history of the o i l industry and at some of the ground rules under which i t operates let us now turn to an examination, in some detail, of the prorationing system in Alberta. - 18 -CHAPTER I FOOTNOTES I - 1. Canadian Petroleum Association, Oil and Gas in  Alberta, p.8. 2. See Appendix I for the disposition of subsurface rights in Western Canada. 3. The following information has been gleaned largely from a) Bank of Montreal, A Guide for Oil and Gas  Operation in Canada, 1965, and b) E. J. Hanson, Dynamic Decade, Toronto, McLelland and Stewart, 1958. 4. Spacing units are established by the provinces and are the minimum area which they will allow a well to occupy. 5. In successful areas bidding for these lease rights is very brisk and very high prices may be paid. As one example, in 19^9, the Amerada Corporation obtained the lease on section 16 in the Redwater discovery townships for a bid of $3,223,230. As they drilled this on 40 acre spacing this amounted to some $200,000 per well. See Hanson, op.cit., p.87 6. Calgary and other settlements in Southern Alberta were already serviced with natural gas by this time via pipe line from the Bow Island gas field, a few miles west of Medicine Hat. 7. E. J. Hanson, Dynamic Decade, Toronto, McClelland and Stewart, 1958, p.47. 8v D. P. Goodall, An Historical Sketch of Oil and Gas  Conservation in Alberta, Alberta, The Oil and Gas Conservation Board, 1957, pp. 3 f f . Mr. Goodall reports that gas waste from the period 1924 to 1931 was estimated to be in the order of 236 to 260 billion cubic feet. Even this must be low however compared to the rate of waste he indicates was taking place in 1932. He reports that in 1932, a provincial committee studying the problem, proposed that the field be unitized and that the production rate be cut from the "current rate of 500 million cubic feet per day to 100 million cubic feet (This was never done though the rate of production was subsequently reduced somewhat). The field was at that time supply-ing about 50 million cubic f t . per day to Calgary. If we are generous and allow another 50 million per day as being required for possible field use, the waste figure then would be in the order of 400 million cubic feet per day (nearly 150 billion per year). 9. Ibid, p.7 19 I - 10. It is interesting to note that the first chairman of the Board was a Mr. ¥. P. Knode, a Texan, who had previously been employed by the Texas Railroad Commission, and had taken part in the introduction of conservation measures in the East Texas field. Mr. Knode resigned in 1939. 11. Hanson, op. cit., p. 49 12. Ibid., p.50 13. Alberta, Oil and Gas Conservation Board, Oil and  Gas Industry, Annual Report, 1948. 14. See Appendix 2 - "Growth ofCanadian Oil Reserves, by Major Fields, to December 1950". (December 1950 saw the inception, once again, of prorationing by the Oil and Gas Conservation Board). 15. The producing fields and their capacity at the end of 1949 were as follows: Leduc; 9~~wells in Lower Cretaceous at 50 b/d MPR 450 b/d 108 wells in Devonian (D-2) at 65 b/d 7,020 b/d 234 wells in Devonian (D-3) at 100 b/d 23,^00 b/d Field Capacity 30,870 b/d Redwater: 278 wells in Devonian (D-3) at 160 b/d 44,480 b/d Turner Valley: Actual production 10,400 b/d Golden Spike: 2 wells in Devonian (D-3) at 900 b/d 1,800 b/d Joarcam: 4 wells in Viking formation at 50 b/d 200 b/d Total capacity end 19^9 87,800 b/d Demand 1949 51,000 b/d Shut in capacity end of 1949 36,800 b/d Sources: - for number of wells, Alberta, O.G.C.B., Oil and Gas  Industry, Annual Reports - for MPR figures, Reservoir Engineering Digest, Nov.20, 1958. MPR figures used here are those as shown in R.E.D. for mid 1951. The MPR figures shown are MPR's before the application of any penalty factors, so, total capacity figure as' calculated above would be a maximum figure. - 20 -Sources - for demand, Alberta, O.G.C.B., Oil and Gas  Industry, Annual Reports. The demand figure for the end of 1949 is half of the sum of the average daily demands for the years 1949 and 1950. I - 16. The producing fields and their capacity at the end of 1950 were as follows: Leduc: 12 wells in Lower Cretaeous at 50 b/d MPR 600 b/d 209 wells in D-2 at 65 b/d 13,585 b/d 297 wells in D-3 at 100 b/d 29,700 b/d Field capacity 43,885 b/d Redwater: 733 wells In D-3 at 160 b/d 117,300 b/d Turner Valley: actual production 9,300 b/d Golden Spike: b wells in D-3 at 900 b/d 5,400 b/d Joarcam: 2b wells in the Viking at 50 b/d 1,300 b/d Stettler: 2 wells in L.C. at 50 b/d 18 wells in D-2 at 110 b/d 8 wells in D-3 at 60 b/d 100 1,980 480 b/d b/d b/d Field capacity 2,560 b/d Excelsior: 22 wells in D-2 at 140 b/d 3,080 b/d Fefin-Big Valley, and Acheson 10 wells 1,500 b/d Total production capacity 184,400 b/d Demand at end of 1950 approx. 95,000 b/d Shut in capacity at end 1950 89,400 b/d Sources: same as shown in footnote No.15. - 21 -1 - 1 7 . See Chapter II for details of the prorationing plan. 18. The Royal Bank of Canada, Oil and Gas Department, Industry Statistics, Calgary, July 31, 1966, p.l. This demand figure is for a l l of Western Canada. 19. Ibid., p.l. This production capacity figure is for a l l of Western Canada. 20. See Appendix 3 - "Growth of Canadian Oil Reserves -by Major Fields, December 1951 to the Present". 21. The, Royal Bank of Canada, op.cit., pp. 2 f f . 22. This was derived by subtracting the 800,000 b/d production figure for 1965, from the oil production potential figure ofWestern Canada, in 1965, of 1,650,000 b/d. 23. MPR's are set in every province and are the rates, presumably based on reservoir characteristics, that the provincial Boards feel to be the maximum at which wells or pools can be produced without avoidable underground waste. The sum of a l l these MPR's in a province are then in fact equal to the producing capacity of that province. 24. M. A. Adelman, "Efficiency of Resource Use in Crude Petroleum", Southern Economic Journal, vol.31 (October 1964), p.107: 25. Hanson, op.cit, p.155 26. The Toronto-Dominion Bank, Petroleum and Natural  Gas Map of Canada, Calgary, 196b 27. Canadian Petroleum Association, Statistical Year  Book, 1965, Calgary, p.36 28. Hanson, op.cit, p.l60 29. The Toronto-Dominion Bank, op.cit. 30. The Canadian Petroleum Association, op.cit., p.36 31. "And equivalent" takes in pentanes plus, propanes, butanes, etc. (largely liquid products recovered from natural gas) not previously included in our crude o i l production quantities. - 22 -I - 32. This yields a total Canadian production figure of crude o i l and equivalents of approximately 920,000 b/d (see Canadian Petroleum Association op.cit., p9) of which, as we have seen, 800,000 b/d was crude o i l . 33. Canadian Petroleum Association, op.cit., p.72. Imports of crude o i l and equivalents were from Venezuela 240,000 b/d, from the Middle East 145,000 b/d, and from Trinidad about 10,000 b/d. - 23 -CHAPTER II THE PRORATIONING REGULATIONS Our aim in this chapter is to study the prorationing regulations in Alberta, from their inception in December, 1950, through various amendments to their form at the present time, and to determine i f these regulations have resulted in the over drilling of o i l pools. Part I will be the description of the regulations, Part II the criticism. Part I: A Description Before we begin we had better explain two terms which we will be running into frequently. One is Maximum Permissible Rate (M.P.R.) and the other Economic Allowance (EA). The f i r s t , M.P.R., is set by the province concerned and is designed to prevent reservoir "damage" and so allow the maximum ultimate recovery of o i l from the reservoir. The M.P.R. "formula" for a well typically takes into account acreage assigned to the well, formation thickness, porosity of the formation, nature of the reservoir drive, and other factors. The "formula" in effect consists of two parts - the first which calculates an o i l in place figure recoverable by the well, and the second which applies factors (based on well spacing, type of reservoir drive, estimated ultimate recovery, etc.) to this figure and hence yields a maximum allowable rate 1 for the well. This M.P.R. may be-reduced by application of "penalty" - 24 -factors i f the well should produce excessive amounts of gas and/or water. Allowed gas is generally 1,000 cubic feet per barrel of o i l and penalties for any amount over this are in direct ratio (e.g. 2,000 cubic feet per barrel reduces M.P.R. by 50$). The M.P.R. is reduced to 67$ by the production of one barrel of water for one barrel of o i l 2 and to 50$ for two barrels of water for one barrel of o i l . The Economic Allowance, was designed by the provincial authorities to allow every operator a supposedly fair rate of return on his investment, and therefore was largely proportional to the depth of well. As Mr. D. P. Goodall (at that time deputy chairman of the O.G.C.B.) put i t in a 1957 address, "The purpose of the economic allowance was to permit wells in pools of low potential to produce at a rate 3 which would pay out drilling costs and operating expenses" , In effect then this meant that in pools where the M.P.R. of a well would be less than the E.A., that the production rate allowed would be the E.A. - i.e. the E.A. was the minimum rate which would be assigned to a well. In cases where the E.A. did govern, the gas and water penalties mentioned above would be applied to the E.A. Under the prorationing plan set up by Alberta in December, 1950 the Alberta O.G.C.B. was responsible for govern-ing the allocation of the "market demand" among the oi l pools in the province, and for governing the allocation of the pool allowable to wells in the pool. Market demand was - and is -arrived at each month from the total of purchasers' ' nominations. Each nomination states the location of the purchaser's refinery, - 25 -means of transportation, gravity and type of o i l required, and the quantity. It is implicit that the price the purchaser is prepared to pay is the price which has been "posted" by him. As explained more fully below the sum of the nominations would then be distributed to pools in the province on the basis of their relative M.P.R.'s. It is clear that under this system no individual producer has any incentive to offer crude at a reduced price as he would not be able to enlarge his prorationed share by so doing. This,of course, is the "aim of the game" - prorationing is a price fixing arrangement principally for the benefit of the producer - not the purchaser as such. The purchaser presumably would be eager to buy as cheaply as possible. In fact, because in most cases the large purchasers are also large producers the above distinction between the two is not very meaningful - the purchasers in "posting" the price at which they will buy are by the same act setting the prices at which - as producers - they must sell. 'The o i l company, in its role as a purchaser, therefore, has its desire for obtaining crude at as low a price as possible tempered by its desire as a producer to obtain as high a price as possible. The independent producer must of course sell at whatever price the large purchaser - producer has determined as best. In "posting" his price the large producer is effectively determin-ing the size of the market which will be served by Canadian o i l . Presumably i f , as a producer, he were willing to accept a lower "well-head" price he could compete with other sources of - 26 -supply in markets further afield. To return to the prorationing regulations the "demand", after being determined as above, was then divided into two 5 grades of crude o i l : 1) light and medium, and 2) heavy. Since the demand for heavy crude exceeded the productive capacity of the pools in this category this grade was not subject to prorationing. Note that this situation is one which has continued to the present day, so that in our study of the effects of prorationing we will be considering only crude in the light and medium grade categories (which, i t must be added, represents nearly a l l of the crude produced). Next the provincial demand for the light and medium crude was allocated to pools in this category by providing that each pool received: a) an allocation equal to the sum of the well Economic Allowance in the pool and b) a share of the residual demand (i.e. the total demand minus the sum of the E.A.'s), this share being based on the ratio of the pool M.P.R. relative to the sum of a l l the pool M.P.R.'s (in this category) in the province. The pool allocation was then distributed to wells by dividing i t by the number of wells in the pool. This procedure was followed with only minor modifications until August, 1957, when the Board announced certain amendments. - 27 -For one thing the Board stated that i t 11.... believes that any economic allowance should afford a prudent operator the opportunity to meet his operating costs and to recover both his drilling and completion costs in a reasonable period of time. There seems, however, very l i t t l e justification for the indefinite continuance of an economic allowance which would permit the several fold recovery of drilling costs."6 As a result i t adopted a two stage economic allowance system. Under the new scheme there was to be an Initial Economic Allowance, much the same as the "old" Economic Allowance had been, which would be effective for the first seven years of the well's l i f e . Thereafter an Operating Economic Allowance would be applied permitting substantially lower rates of production. Another change made by the Board was that a residual M.P.R. plan for prorationing would be instituted, to become effective January 1, i960. This was a plan whereby the residual demand (the "demand" remaining after the E.A.'s had been satisfied) would be allocated on the basis of the pool M.P.R. less the pool E.A. Other amendments were made in 1961 regarding economic allowances, due to special problems encountered as a result of the growth of secondary recovery schemes, and of unit operations. As will be pointed out in Part II below, the above prorationing regulations, which were not significantly changed by the amendments from their original form of 1950, were far from being ideal. They led to a great amount of - 28 -overinvestment taking place, primarily due to the encourage-ment which they gave to overdrilling. This fact was, of course, commonly recognized and in a hearing held by the Board in November, 1963, for this purpose, representations were received from members of the industry as regards their views on the whole prorationing scheme and as to changes, i f any, which they would recommend. Response by the o i l industry to this opportunity to air i t s 1 views was great and submissions were presented by nearly a l l of the major producers - and the minor ones as well, through their "Independent Petroleum Association of Canada" (I.P.A.C.). Most of the submissions pointed out deficiencies in the proration plan (or at least what the submittors felt to be deficiencies), the most commonly cited being the encouragement that the plan gave to the drilling of unnecessary development wells. As a result of these hearings the 0 G.C.B. in 1964 issued major amendments to the prorationing regulations. These amendments are to be implemented over a five year transition period ending in 1969. The highlights of the 7 new plan are as follows: a) The light and medium crude o i l category will continue to be the only one subject to pro-rationing. b) The provincial allowable, or "market demand", will continue to be determined according to the receipt of purchasers': nominations. - 29 -c) The Economic Allowance is to be reduced so that i t will permit the recovery of completion and operating costs, but not drilling costs. The Economic Allowance under the new plan will be a floor allowance scaled with depth.8 d) Allocation of the provincial allowable among pools is to be changed from allocation on the basis of M.P.R. ratios, to allocation on 9 the basis of reserves. e) Allocation of the pool allowable among wells in the pool is to be changed from a well basis to an area basis. f) Some form of maximum daily production rate restrictions will be retained through the use of an amended M.P.R. formula."^ Now, before going on to consider in more detail the shortcomings (particularly before the 1964 amendments) of the Alberta prorationing regulations one other factor, not directly connected with prorationing, but s t i l l inter-related with i t , must be mentioned. This is the well "spacing unit", as prescribed by the Board, which will be seen to play a very important part in our consideration of overinvestment that follows. As indicated earlier, the Board has effective control over the location of a l l wells, in that a licence must be - 3 0 -obtained from i t before drilling may be commenced. A well "spacing unit" is the minimum area which may support a well, and its size may vary from pool to pool depending on the reservoir characteristics and the type of crude. Prom the time of Leduc up to 1962 the spacing unit in nearly a l l fields was 40 acres. In a few fields such as Lloydminster, where the crude is of low gravity and reservoir drive is weak, closer spacing is allowed - much of Lloydminster is on 10 acre spacing. In 1962 the minimum allowable spacing unit was increased to 160 acres - except, again, that exceptions to smaller spacing could be made i f warranted. At the 1963-64 prorationing "hearings" referred to above the issue of well spacing units was one frequently raised. As we indicated, i t was decided by the Board that the allocation of allowables within pools would be changed, from the previously used well basis, to an area basis. The minimum spacing unit of 160 acres was maintained - however a very important distinction was made as between a drilling spacing unit and a producing spacing unit. It was decided that the minimum drilling spacing unit would be maintained as 160 acres but that larger spacing units could be recognized for production purposes. That is, a well could be allocated additional contiguous area i f satisfactory evidence prevailed that the area so allocated was underlain by o i l and i f i t was felt that the drilled well could efficiently produce this o i l . As the "Report" states: "The Board - 31 -believes that allocating up to a maximum of eight quarter section drilling spacing units symmetrically located about a drilled quarter section spacing unit would not be excessive in certain cases. Assuming necessary evidence for validation, the Board sees no reason for not allocating additional area on a l l sides of a drilling spacing unit A reasonable upper limit for a production spacing unit in the Board's opinion would, therefore, be two and one quarter sections, although a lower limit might be appropriate where drilling spacing units are smaller than a quarter section." l i -l t is clear that this change will work to best advantage in pools where lease ownership areas are held in large blocks. If leases are held in small blocks (160,320 acres) by separate owners drilling, of course, will take place at these spacings. Part II: A Criticism As we have pointed out previously, prorationing leads to overinvestment in two ways: l) Due to the fact of prorationing itself which, because i t serves to maintain a high price by restricting supply, encourages the development of high cost fields even though low cost capacity is available-and 2) Due to the regulations through which proration-ing is put into effect, and which may lead to overdevelopment of o i l pools. It is with the latter, the encouragement that the Alberta regulations have given to the overdevelopment of o i l pools, - 32 -that we will be concerned in this section. We will f i r s t consider the prorationing regulations in the period 1950 to 1964. Then we will look at them again after the very-substantial 1964 amendments. In our study we will be including effects due to regulations which govern the manner in which leases may be held, and effects due to regulations which set out the minimum well spacing units that are allowed. Strictly speaking neither of these is "chargeable" to prorationing in that they would exist (as they do in the other provinces) even in the absence of prorationing. Notwithstanding, for our purposes i t is to be understood that when we talk of overinvestment due to prorationing regulations that we are including the effects of these regulations as well. We have spoken of the overdevelopment (or overdrilling) of an oil pool. Just what do we mean? When may a pool be considered, overdrilled? In the book "Well Spacing" the authors, Craze and Glanville, state that: "Once an adequate number of wells has been drilled to provide the necessary geologic information, and to permit a maximum efficient rate of with-drawl without excessive individual well rates, then beyond this minimum number additional producing wells have no material effect upon ultimate recovery."12 That is, once enough wells to develop the pool M.P.R. have been drilled this would be the maximum number that you would want. More wells than this would not allow a greater ultimate recovery from the pool nor permit a greater pool M.P.R. If more wells than this were to be drilled the M.P.R. per well would have to be less so that the pool M.P.R. would not be exceeded. - 33 -For example, i f we assume that the spacing required to enable a pool to be produced at its M.P.R. was 160 acres and i f wells were in fact drilled at 40 acre spacing, then 3 of the 4 wells would be "wasted" in the sense that their presence should add nothing to the allowable production rate of the pool. The question remains "What is the spacing which will allow a pool to be developed at its M.P.R.?" This obviously will vary from pool to pool depending on reservoir character-istics. Again referring to Craze and Glanville they note that: "Establishment of interference over great distances in a reservoir formation has done much to support the attendant conclusion that a well can drain a large area effectively in both limestone and sand-stone formations through the complete range of permeabilities encountered." 13 They note with approval the trend in the U.S.A. to 40 acre and 80 acre drilling units and give the impression that in most cases much wider spacing than this would be in order. They point out that: "Texas producers are at a substantial disadvantage in competing with foreign o i l production from fields developed on extremely wide spacing, in many cases ranging to more than 2,000 acres per well."l4 As regards our Canadian case i t is clear, from the fact that the minimum allowed spacing in Alberta is now 160 acres in most new pools, that this must be the minimum spacing which the authorities consider as being necessary to enable a pool to be drained at its M.P.R. And as we have noted above in our discussion of spacing units, the O.G.C.B. now feels that in fact nine quarter sections (i.e. 1,440 acres) might in some cases be a close enough pattern. - 34 -At this point a critic may reasonably be expected to ask, "All very well to talk about "most efficient" spacing and production rates but might not a rational producer be willing to d r i l l extra wells in order to deplete a pool more quickly, even at the risk that in so doing he may be reducing the total amount of o i l recoverable? In other words might not the "present value" (to him) of his o i l resource be maximized by more rapid development than the "most efficient rate"? In this case would not closer well spacing be justified?" The answer to these questions would be "yes" - i f we assumed that the producer would be allowed, even in the absence of prorationing, to deplete the pool as he saw f i t . However this assumption would not be a good one - with or without prorationing the provincial authorities will enforce field regulations in the interest of "conservation". They certainly would retain the responsibility for setting M.P.R.*s. In answer to our opening question then, "When may a pool be considered over-drilled?", we can say that i t is overdrilled when i t contains more wells than are necessary to develop the M.P.R. of the pool. Let's consider now how the 1950 prorationing regulations encouraged over-drilling. The three worst features of the regulations in this regard were: 1) That the well concept was used as the basis of allocating the pool allowable to wells. The pool allocation was distributed to wells by - 35 -dividing i t by the number of wells in the pool. 2) That provincial demand was allocated to pools on the basis of M.P.R.'s. This too helped emphasize the importance of the well in the allocation base, because the "life factor" used in the formula by which the well M.P.R. was calculated was biased towards 40 acre spacing. That is i t would give, for example, two wells drilled at 40 acre spacing a greater combined M.P.R. than 15 i t would one well drilled at 80 acre spacing. 3) That an Economic Allowance was given to each well the purpose of which was to enable the well to operate at a rate (if i t was capable of it) suf-ficient to "pay out" drilling costs, completion costs, and operating expenses. This in fact near-ly guaranteed that anyone drilling a well in a proven area would be assured a reasonable return on his investment. Let us look at a very simple example showing the over-investment tendency due to using the well as the basis for allocating the pool allowable. Assume a hypothetical province where we have two o i l pools, X and Y, each with an M.P.R. of 1,000 b/d, and that each pool is divided in 3 - 160 acre leases, owned by the different operators A, B, C, etc. as shown in Fig. 2-1. As - 36 -one well is drilled per lease. Assume further that our provincial demand is 1,200 b/d and that the E.A. for each well is 50 b/d. As the M.P.R.'s of each pool are the same we can see, without calculation, that the allowable allocated to each well would be 200 b/d. Now consider what happens when operator A drills a second well (let's assume for simplicity that this leaves the pool M.P.R.'s unaffected though in fact the "li f e factor" in effect referred to above would result in an increase in the M.P.R. of pool "X"). First we give each well i t s ' E.A. of 50 b/d (total 350 b/d). The excess, or residual demand of 850 b/d is then prorationed to the pools in the ratio of their M.P.R.'s: Fig. 2-1 Pool X Pool Y - 37 -Amount prorata.oned to pool X = 850 b/d x Amount prorationed to pool Y = 85O b/d x 1,000 b/d 2,000 b/d 1,000 b/d 2,000 b/d 425 b/d 425 b/d Each well in pool "X" now produces: 50 b/d + 1/4 x 425 b/d = 156 b/d Each well in pool "Y" now produces: 50 b/d + 1/3 x 425 b/d = 192 b/d Therefore everybody loses except operator A who drilled the extra well and is now allowed to produce 312 b/d (v.s. 200 b/d before). Note that even the operators in pool Y lose out. Taking the l i f e factor into account would reinforce the desireability of operators in a pool drilling more wells as this would increase that pool's M.P.R. and hence give i t a greater share of the residual demand. Note that even i f only one operator controlled the whole of a pool that this incentive to overdrilling would s t i l l exist. In one of the 1957 amendments to the regulations a change was made whereby the demand in excess of E.A.'s was distributed to pools, not in the ratio of the pool M.P.R.'s but rather in the ratio of pool M.P.R. - E.A. for the pool  total of a l l pool M.P.R.'s - total of a l l pool E.A.'s Whereas this was a move in the right direction i t did not significantly improve matters - applied to our example above i t would have meant that, after A had drilled his second well, the wells in Pool Y would have received allowables of 196 b/d and those in pool X an allowable of 153 b/d. - 38 -Turning to the Economic Allowance provision of the regulations i t seems obvious that this would be an encourage-ment to overdrilling and to the drilling of high cost sources. It's clear that the prorationing was biased towards the "E.A." type wells (i.e. those wells that would be assigned an E.A. in excess of their M.P.R.) These wells would, receive a higher allowable than would have been the case i f allowables had been distributed strictly on an M.P.R. basis. Consider an operator in a low reserve per acre field who, say, has just drilled a well at 160 acre spacing -assume the well M.P.R. is 25 b/d, and the E.A. is 50. b/d. He of course would produce 50 b/d. Now i t is not hard to conceive of him saying "Why don't I d r i l l another?" Indeed, why not? Of course our operator must have a sufficiently good reserve that he can produce each well for the necessary number of years required to pay out his investment, but i t can be readily seen that, up to boundary of this constraint, he has every incentive to keep onodrilling. The effect of the prorationing regulations, then, plus the fact that the minimum drilling spacing unit up to 1962 was 40 acres, and. plus the fact that the manner in which lease rights were allocated led the fragmentation of lease ownership in nearly a l l pools, resulted in many of the fields being develop-ed at the minimum spacing allowed (i.e. 40 acres). Moving on, let's now consider the implication of the 1964 amendments, which go a long way in making the regulations "neutral" insofar as pool development is concerned. The most important amendment is the one changing the - 39 -method of allocation within pools from a well basis to an area basis. This removes the previous incentive to d r i l l extra wells so as to be awarded a greater percentage of the pool allowable. As the Board points out, "The area method of distribution results in each well, subject to the effects of any minimum allowance and any restrictions on maximum well rates, receiving a fraction of the total pool allocation equal to the ratio between the area allocated to the well and. the total areas allocated to a l l wells in the pool." 16 Note that this means that an operator must not only "own", say, 10$ of the leases to be awarded 10$ of the pool allow-able, but that he must have enough wells drilled, in the 1' view of the Board, to efficiently deplete the area concerned. Carrying the thinking of this amendment back to pools already developed, the Board made another change allowing the institution of a system of "lease allowables". The idea here is that in pools where wells in excess of the number required to adequately develop the pool have been drilled, that enlarged production spacing units would be allowed thus permitting the abandonment of surplus wells without, however, affecting the allowables assigned to them. With respect to the Economic Allowance we have seen that the new minimum allowances were greatly reduced so that they now permit only "the recovery of completion and operating 18 costs and give a satisfactory return on the former." The main constructive result of this is that i t will no longer pay an operator to d r i l l a well strictly for the sake of the E.A. he would receive. - 40 -The Board in retaining an E.A. at a l l is in effect expressing its view that: 1) Abandonment of wells, before the production of a l l economically recoverable o i l has taken place, should be discouraged. For example when, due to the prorationing system, the allowable assigned to a well becomes less than necessary to pay the well operating expenses, then the allowable should be in-creased sufficiently that production costs can be covered. 2) Production from low reserve per acre pools (i.e. high cost pools) should be encouraged, i f at a l l feasible, once the pool has been found. This is achieved then by the giving of an allowable adequate to encourage the completion and operation of the well. With respect to encouraging the development of low reserve per acre pools the Board states that "It realizes that such production could have a slightly adverse effect on the overall cost of producing o i l in the Province, but believes that such an effect should be considered secondary to conservation.""^ i t points out though that recognizing the wider spacing now allowed that in most cases low reserve per acre pools could be economically drilled and operated without dependence on the minimum allowance. That is, the M.P.R. for a well in such a pool might, i f the well were on wide enough spacing, be profitable and greater than the E.A. - 41 -The third amendment of significance is that the allocation of the provincial allowable among pools is now to be made on the basis of reserves. This reinforces the effects of the above two changes in placing less em-phasis on the well in the determination of allowables. We have noted how use of M.P.R.'s as the basis of alloca-tion could lead to overdrilling in a pool so as to increase the pool's M.P.R. - under the old scheme pools developed on greater than 40 acre spacing would experience a pro-gressive reduction in allocation per acre as spacing in-creased (through the effect of the 'life factor' in the M.P.R. formula). By the "reserves" method two pools each with the same reserves would both be allowed to produce at the same rate (so long as the rate was below the pool M.P.R. - which in the present situation of considerable over capacity would nearly always be the case). This again is assuming that, in the opinion of the Board, each pool has enough wells to "properly" develop the pool capacity. Under the- new regulations the "old" M.P.R. formula with its attendant l i f e factor is to be discarded. Restrictions as regards maximum permissive production rates are to be maintained however but a new formula for this purpose is to be devised. If production rates were to reach the stage where M.P.R.'s were to become generally relevant then M.P.R.'s would again determine production rates regardless of the reserves of one pool vis-a-vis another. - 42 -In summary the 1964 amendments would seem to result In a body of regulations which, in themselves, give mini-mum incentives to overinvestment. It appears that the effect of these amendments, along with the new minimum and maximum allowed production spacing units of 160 acres and 1,440 acres referred to above, w i l l be that new pools w i l l be developed on spacings in this range. To what extent they w i l l tend towards the upper figure depends on the pool characteristics and on the distribution of the lease ownership. We might fault the retention in the regulations of the minimum allowance provisions which to some extent encourages the development of marginal pools (though we would emphasize that i t is the fact of prorationing i t s e l f which is mainly to blame in this regard) - however under the new allowable sizes of production spacing units i t seems l i k e l y that such pools would be developed on wide spacing so that the amount of money spent in this fashion would not be large. The worst feature remaining, conducive to over-investment, is the system of lease disposition which in practice requires that the ownership of pools be fragmented. This doubtless w i l l continue to lead to closer well spacing than ideally required, though the consequences w i l l no longer be as bad as they previously were due to the now 160 acre minimum spacing unit. This concludes our detailed look at the history and regulations of the Canadian (or Albertan) prorationing - 4j5 -system. Let us now turn to Chapter III where we will make an attempt to calculate the amount of overinvestment that has been encouraged by prorationing. _ 44 -CHAPTER II FOOTNOTES II - 1. See Appendix IV for a detailed description of the Alberta M.P.R. formula. 2. The Catawba Corporation, Petroleum Exploration  in Canada and the United States, New York, 1963, P. 23. 3. Goodall, op. cit., p.17. 4. Any company wishing to purchase oi l in Alberta must f i l e a nomination with the Board prior to the middle of the month preceding the month in which the o i l is desired. The sum of a l l such nominations then becomes the provincial demand for the following month and is the amount which the Board prorations among the producers. 5. It appears that a l l crude of 25° A.P.I, gravity or less falls into the heavy category, though there does not seem to be any hard and fast rule in this regard. 6. Alberta, The Oil and Gas Conservation Board, Report and Decision on Review of Plan for Proration of Oil to Market Demand in Alberta, July 1964, p.43. 7. These are to be found in detail in Ibid., pp. 171 f f . 8. An Economic Allowance may be provided in a proration plan as either a basic allowance or a floor allowance. If i t is a basic allowance the amount of demand required to satisfy the E.A.'s is allocated first and the remalng demand is then allocated in accordance with factors such as reserves or M.P.R.'s. If, however, the mini-mum is a floor allowance the total demand is firs t allocated among pools in relation to reserves or M.P.R.'s, then an adjustment is made so that each well allocated an amount less than the floor allowance in the fir s t instance is allocated an amount equal to It, the allow-ables of other wells then being reduced accord-ingly. For "pros" and "cons" of the two systems see Ibid., pp. 66 ff - 45 -II - 9. The scheme adopted is based on a formula which takes into account both ultimate and remaining reserves. The reserve figure assigned to a pool is made up of 50$ of the pool's ultimate reserves plus 50$ of it's remaining reserves. For more details see Ibid., pp. 114-117. 10. It should be obvious that with the present state of over-capacity in Alberta (which looks like continuing for some time) M.P.R.'s will seldom be required. Also since under the new regulations production is to be allocated to pools on a reserves basis, M.P.R. figures will no longer be required for this purpose of allocating demand. As a. result i t would appear that in future much less will be heard of M.P.R.'s in Alberta - this is too bad in that i t may take attention away from the amount of productive over-capacity existing. 11. Ibid., p. 135 12. Craze and Glanville, Well Spacing, p. 35 13. Ibid., p. 47 14. Ibid., p. 49 15. See Appendix IV for a fuller description of the l i f e factor modifier. 16. O.G.C.B., "Report and Decision pp. 123, 124 17. It should be mentioned that the area method is modified by the incorporation of an "area-recovery" factor. This acknowledges the fact that enhanced recovery operations in portions of the pool must be allowed for so as to achieve a more equitable distribution and to encourage improved recovery efficiency. 18. O.G.C.B., "Report and Decision ", p. 173. 19. Ibid., p.28. - 46 -CHAPTER III THE DETERMINATION OP OVERINVESTMENT In this chapter we will make a calculation of the amount of overinvestment that has occurred in Canada's o i l industry-due to the fact of prorationing itself and due to those provincial government "field" regulations which, either inside or outside of a prorationing scheme, have encouraged the over-drilling of fields. Part I following will be a calculation of the amount of overinvestment due to over-drilling. Part II will be a con-sideration of the amount of overinvestment due to proration-ing itself - i.e. the amount of overinvestment resulting from the development of high cost fields and which is caused by the incentive that a prorationing scheme gives to the development of such fields (in the form of a maintained high price and a "guarantee" that each producer will receive a share of the provincial "demand"). This development is at the "expense" of the low cost fields which must suffer shut-in capacity. Part I: Overinvestment due to Poor Field Regulations As outlined in Chapter II the most desireable well spac^ ing to develop an o i l pool is now felt, by the Alberta authorities at least, to be a minimum of 160 acres and a maximum of 1,440 acres. We also have seen that the pro-rationing regulations in Alberta, as they existed up to the time of the 1964 amendments, encouraged operators in that Province to d r i l l wells to the minimum spacing allowed, which - 47 -up to 1962 was 40 acres. It is obvious then that on the basis of present thinking at least three out of four of a l l development wells drilled on 40 acre spacing can be classified as excess or waste - this would be the proportion assuming a field whose "best" spacing was taken to be 160 acres. Note that i f we were to consider the other extreme and imagine a field where 1,440 acre spacing was in order, but which in fact had been drilled out at 40 acres, that our proportion of waste or excess wells would then not be a mere 3 out of 4 but 35 out of 36. It is to be recalled that we are labelling these wells on close spacing as "excess" in the sense that their presence should not have allowed a pool to be depleted at any greater M.P.R. In our following analysis of overinvestment due to over-drilling we will follow a conservative tack and go on the assumption that for most pools the "best" well spacing would in fact be the minimum now allowed - i.e. 160 acres (in Alberta). In a few cases where the fields are very prolific we will say that 320 acres should have been the minimum allowed - and similarly in a few others where we consider field characteristics to be quite poor we will use 80 acres as our "standard". We will brand as excess wells drilled on closer than 160 acre spacing in the other Western provinces as well, where prorationing does not exist. It is to be emphasized that waste due to poor government regulations is not due solely to those regulations within a prorationing scheme -even without prorationing government regulations relating to M.P.R.'s, the manner in which leases may be held, and so on may lead to overdrilling. In Saskatchewan where most fields have been developed on 80 acre spacing, and in Manitoba where they have been developed largely at 40 acres we can conclude that the reasons for this are to be found in the minimum spacings permitted in these provinces and in the M.P.R. formulas of each province which would have encouraged d r i l l -ing up to this minimum. In British Columbia a l l fields have been developed at close to 160. acre spacing so that we will say in this province no excess i n f i l l drilling has occurred. Our approach then - with only a few exceptions - is to consider a l l development wells drilled in Western Canada (in the light and medium crude o i l category only) on closer than 160 acre spacing as being excess - i.e. as representing overinvestment. Looking at the actual well spacing field by field and comparing these spacings to what we consider they should have been - usually 160 acres - we determine the number of excess development wells. By proceeding in this manner -see Appendix V - we have determined that approximately 8,100 development wells in the provinces of Alberta, Saskatchewan and Manitoba, should never have been drilled. Now how much investment do these 8,100 wells represent? In considering this i t will be well i f we take time to gain an understanding of the steps involved in bringing a well into production. Stage 1 of course is the drilling of the hole itself down to the o i l producing formation. This requires the •. - 49 -erection of a derrick and the installation of the necessary-drive motors, drawworks, mud pumps and tanks, etc. The well is "spudded" (started) with a hole perhaps 15 inches in diameter and a steel "surface casing", about 10 inches in diameter and which may run for some 300', is placed and cemented in the top portion of the hole (the space between the casing and the d r i l l hole wall is cemented). The pur-pose of this surface casing is threefold -.1) to prevent the borehole from caving in where the surface formations are soft, 2) to keep water from porous sands from entering the hole, and 3) to provide a firm anchor for the attachment of surface 1 blow-out preventors. After this casing has been set the remainder of the well is drilled - generally no further casing is installed during drilling. Now assuming that the development well has encountered the expected producing formation i t must then be "completed". Let us call this stage 2. The first thing done is that a steel casing is installed the complete depth of the hole and cemented. When the producing formation, (or"pay zone") is firm and not liable to caving, the casing is stopped immediately above i t and the productive layer left unsupported. If the productive layer Is not firm then the casing is run through i t and cemented. Holes are then shot through the casing opposite the productive layer by means of a "gun perforator". In some formations the producing strata may require treatment to induce the o i l to flow. This treatment may take the form of acidizing or fracturing. Acidizing is - 50 -used in limestone formations - a solution of hydrochloric acid is forced into the producing formation thus dissolving the limestone and enlarging the flow channels in the forma-tion. With fracturing water or o i l is pumped into the formation at high pressure causing fractures in i t near the well through which the o i l then flows more readily. Whether the well produces by natural flow - i.e. the gas or water "drive." being sufficient to force the o i l to the surface - or requires pumping, the oil is brought to the surface via a string of small pipe (about 2 or 3 inches inside diameter) called tubing which is hung from the well head and extends to just above the producing formation. In the case where a well flows naturally an assembly of valves and fittings, known as a Christmas tree, is installed at the well head for purposes of controlling the flow of the well or shutting i t in. Should the natural reservoir drive be insufficient to raise the o i l to the surface pumping may be resorted to. The type of pump which is most widely used is a simple reciprocating plunger pump, actuated by "sucker rods" from a surface pumping unit, and which run inside the tubing. As an alternative or as a complement to pumping there are various "secondary recovery" techniques that are used. In a depleted reservoir where water drive is inactive and much of the original gas has been produced, considerable quantities of o i l may s t i l l remain in the formation. One technique to recover at least part of this o i l is "water flooding" whereby water is injected under pressure into the - 51 -formation via Injection wells, thereby displacing the oi l towards nearby producing wells. Another is "gas in-jection" which may be used later in the pool's l i f e as a secondary recovery scheme; alternatively gas may be in-jected into the reservoir at an early stage in the field's l i f e so as to reduce or eliminate the decline in reservoir pressure that would normally occur - this latter process is known as "pressure maintenance". The final stage, stage 3, of bringing a well into production requires the construction of surface facilities. Commonly the production from each well is led through a "flowllne" from the well head to a "gathering station". The gathering station, which may handle the production from several wells in the vicinity, is equipped with separators which serve to seperate the gas from the o i l , and with tanks in which the o i l can be gauged and from which any water that settles out can be drained. From the gathering station the crude is then usually pumped directly to storage tanks. Going on: now with the estimation of the amount of over-investment that our 8,100 excess wells represent we shall p follow Mr. Hanson who has calculated the cost of bringing a well into production using a breakdown which roughly cor-responds to the three steps that we have outlined above. He uses for his example a well drilled in the Leduc -Woodbend field and which is 5,200' in depth. The cost of drilling the hole corresponding to stage 1 above he gives as approximately $55,000 . Stage 2, assuming - 52 -a well requiring a pumping unit, would cost, according to him, about $32,000 - of this the pump,sucker rods, etc., would account for about $10,000. He calculates that the surface facilities - stage 3 -, charging the cost of these facilities to the individual well, would be worth an addition-al $18,000. This a l l adds up to a total well cost of some $105,000. For our purposes though and assuming we were consider-ing the same well our total would be somewhat less. In the fir s t place we will make the assumption that every well requires pumping (if not in its early l i f e than certainly later on and even though secondary recovery or pressure maintenance schemes are resorted to) but that not every well will require a new pumping unit. We will say that each pump can be used for 2 wells - that is we assume i t would be used on one well until no longer required and then moved to another. In this way we will take the capital cost of pump-ing equipment chargeable to each well as being $5,000, not $10,000. Secondly i t is our assumption that each installation of surface facilities is made to service ^se^veral wells. As a result we feel there would be no significant saving in these facilities through the drilling of fewer wells at a wider spacing - except for the case of flow lines and in connection with some road and fence work, which we will assume (again following Hanson) would amount to some $2,000 per well. The - 53 -well cost that we want to consider then as appropriate to the saving which we would expect i f the well had not been drilled would be $84,000. This figure must be modified further however.- as i t is based on a 5,200' well in Leduc and certainly the excess wells which we are considering are not a l l in Leduc nor are they a l l 5,200' deep. Nearly always the most important factor in the cost of a development well is depth. There are however many other factors which in some cases can prove to be very significant indeed.. One is location of the well - drilling in say the Sturgeon Lake field of Alberta, about 200 miles north-west of Edmonton, would be more expensive than in Leduc, just outside of Edmonton, for the reason of higher transportation costs. In addition a field in a muskeg area may require drilling in the winter months when-access to i t would be easier, though admittedly this is a matter of more import-ance in the drilling of exploratory wells than i t is for development wells which we can assume are drilled after some sort of reasonable a l l weather access to the field has been built. Another factor important in the cost of a well is the hard-ness of formation which must be drilled, through to reach the pay zone - this can be of great importance in the time re-quired to d r i l l a well. Not only is the drilling rate itself much slower in harder material but the bits wear out more quickly necessitating frequent interruptions for the - 54 -pulling out of the d r i l l stem, changing the bit, and then •running in 1 again. Also important is the cost of treating a well to "bring i t in" - this can vary greatly from a very small amount in some cases to a few thousand dollars. Even with a l l this in mind however our approach will be to assume that the cost per well due to a l l these other factors will be, on the average, the same as the costs which have been used for these items in the Leduc well example above. This will leave us with the depths of the excess development wells v.s. the depth of the Leduc well as being the only factor that we will take into account in adjusting the above $84,000 figure. The average depth of the 8,100 wells which we have said are excess works out to 4,650' (see Appendix VI). Knowing this we could proceed on the assumption that a good estimate of their cost would be to take the cost of a well of this average depth and multiply i t by 8,100. Implicit in this procedure however is that the total cost of development wells increases linearly with depth which i f i t were the case would make admissible this procedure of estimating the sum of in-dividual well costs by taking the number of wells times the cost of a well of average depth. However this is not the case - well costs do not increase linearly with depth. In the shallow depth ranges - perhaps up to 3,000' - they increase in less than proportion to depth due primarily to the fact that the costs of transporting and erecting the - 55 -drilling rig (which we may look upon as a fixed cost and 4x hence one that does not increase significantly with depth ) loom relatively large compared to the drilling and completion costs (which we may look on as variable costs and which increase in greater than proportion to depth-*). With deeper wells - those of 4,000' and over - drilling and completion costs become a much greater part of total costs with the fixed costs decreasing in importance so that for these wells costs increase in more than proportion to depth. With this type of cost relationship then the actual average well cost of a group of wells is greater than the cost of a well of average depth. For example i f we had one well of 3,000' depth and another of 5,000' depth the average cost of these would be greater than the cost of a well of 4,000' depth. We have determined the average depth of the excess develop-ment wells to be 4,650'. Assuming a linear cost relationship 4 650' the cost of a well of this depth would be ^' 200' x $84,000 or about $75,000. From the type of cost relationship described above however and recalling our assumption that once over 4,000' well costs increase in more than proportion to depth i t follows that the cost of a 4,650' well would be less than this - probably in the order of $70,000. Finally though in conformity with the reasoning that the cost of a 4,650' well will be less than the average cost of a group of wells of 4,650' average depth i t is clear that average cost figure we want is more than this. How much more we're not - 56 -sure but i t is nearly certain that i t would lie somewhere between $70,000 and $80,000. As a check on this result and as guidance to just what actual average cost figure to use we refer to Pig. 3-1 showing a curve fitted to well cost data that is available for some 7 Alberta and Saskatchewan fields. These costs are for wells complete with pump and are representative of "typical or o average field wells" 0. This graph yields a cost figure for a well of 4,650! depth of $67,000 - tolerably close to the $70,000 value above. As regards the average well cost figure in which we are interested this too can be determined from the information given by Pig. 3-1. This is done in Table 3-1 where the excess development wells (those considered in Appendix VI in arriving at the average well depth of 4,650') have been segregated into depth classes - multiplying the number of wells in each class by the appropriate cost value taken from the graph leads to the result we require. Table 3-1 Depth Class No. of Wells Cost per Well Total Cost 2,000' - 2,500' 791 $ 42,000 $33,200,000 2,500' - 3,000' 125 46,000 5,750,000 3,000' - 3,500' 1,022 51,000 52,300,000 3,500' - 4,000' - — — 4,000' - 4,500' 108 63,000 6,800,000 4,500' - 5,000' 841 69,000 58,000,000 5,000' - 5,500' 1,697 78,000 132,200,000 8,250,000 5,500' - 6,000' 95 87,000 6,000' - 7,000' 255 105,000 26,800,000 7,000' - 8,000' 59 132,000 7,800,000 8,000' - 9,000' 574 3,b67 165,000 94,500,000 $425,600,000 Average cost of excess development well = $425,600,000 = $76,500 /well 5,567 wells - 57 -fr fli fif 33 l . l - U M l m m il IHf lillli i n : \\ ' . ' i t ! 4 ! ; S t f j j l l t j li3 Iii! 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' i . 3ei i'-.'.'M 6 St io | i l m 3-! 434" ill I f - i l l g i l ' • f ' T ; ii ':.".!• •! . . . . '.:' ) 414 Hi: 1:1 Ttr"H3l:fi ,:s\. f i f i ! - • t1 %\ Tnrf r 31 HI; • :' i.fil: ; ii i:iii;: : :j . ; b ,!:••• il ;i ;;;! ;:; | 1:1: f .1:3 3; Ifli iff: •44-in.| IT'-* 1 ci' :|i|iiii i i i p M »tr i r i4*r i; r;: litiliiij . t h i r l . ! fnif ;u '•\Y> ifill Mb 1 i t i 1 1 j; 1 Hf i ;; ) • ! ! } : • ihillih; Iii'! 4 : l | I-i; HI] iili lilf Ii jfil 1 n {•IS: ; It •' f r: H3 -lthii: ll+ ttl i l L M i t l i x t i - 5» -This average cost figure Includes f u l l pumping costs for every well which based on our figures above means $10,000 per well. Our assumption previously (p.52) though was that pumping costs would be only half this amount per well on average so $5,000 must be subtractracted from the . $76,500 figure yielding a final average cost per well of $71,500. We will use this amount as i t jibes very well with our previous calculations and lies within the $70,000 -$80,000 range which we would have expected. Finally then we arrive at an overinvestment figure due to too many development wells of $71,500 x 8,100 wells or approximately $580 million. Note that this figure does not include the day to day production costs of these wells. Let us check this overinvestment figure against figures published annually by the Canadian Petroleum Association (CP.A.) in their Statistical Year Book. For the years 19-47 to 1965 inclusive the total of expenditure made by the o i l industry in Western Canada under the heading "Development Drilling - Productive - Oil" and including the given allowance 9 for overhead, amounted to some. $1,3^4 million. We assume that the costs shown under this heading include the costs of drilling and completing development wells but are exclusive of any costs for pumping equipment or surface faci l i t i e s . This is common usage.^® In this time period, 1947 to 1965, approximately 22,000 productive development o i l wells were drilled in Western Canada,11 and of these our claim is that about 8,100 were - 59 -excess - i.e. nearly 37$ . We can say then that the amount of excess expenditure which has been made under this category "Development D r i l l -ing" amounts to 37$ x $1,344 million or $498 million. In addition to this we must include expenditures made on flow lines and on pumping fac i l i t i e s . As these amounts are not shown seperately in the CP.A. statistics we will use the same figures for these items as we allowed above - i.e. $2,000 per well for flowlines, roads, and fencing, and $5,000 per well for pumping equipment. The expenditure on these items then for the 8,100 excess wells equals $7,000 per well x 8,100 wells or $57 million. So the total overinvest-ment figure calculated in this manner comes to some $555 million, reasonably close to the $580 million of our previous estimate. Again this figure does not include any day to day production costs. Let us now look at operating costs and calculate the amount of money spent in this manner on the excess wells. The expenditures which we wish to consider here include money spent on such things as power to operate the pumping units, maintenance on the pumps, tubing, etc., and keeping the wells "clean". In some fields wells will "sand up", "mud up", or "paraffin up", necessitating a shut down, the li f t i n g of sucker rods and tubing, and. the lowering of a "cleanout string" so the well can be cleaned. (In fields where sand, mud, or paraffin is really bad wells may be off production one quarter to one half the time and because clogging begins again as soon - 60 -as production is resumed they may be on maximum production only a small part of the time). In addition i f the field 12 produces a paraffin base oil problems may be encountered with paraffin build-up on the walls of the tubing - some-times this may be prevented by heating the tubing; sometimes i t is necessary to pull the tubing and steam the paraffin off. We will not here consider operating expenses connected with the operation and maintenance of surface equipment following our reasoning that even with fewer development wells the same quantity of surface facilities would be required. Referring again to data published by the CP.A. these show that expenditures of some $950 million were made on the "Operation of Wells" in the 19^7 to 1965 period. 1^ These include expenditures on the operation of "Related Facilities" which we take to mean surface facilities, but,a breakdown is not given between expenditures on wells and those on 14 fac i l i t i e s . Following Mr. J. J. Arps i t will be assumed that 60$ of these costs are directly traceable to the well -i.e. 60$ x $950 million or $570 million. This means that the expenditures which have been made on the operation of the 8,100 excess development wells is in the order of 8A00 x $570 million or some $210 million. 2~270"00 Had the excess wells not been drilled the throughput of the remaining wells would have been increased. Would this have increased their operating costs? Mr. Arps says "no" -- 61 -"The field cost of operating any given well is l i t t l e different, within reasonable limits, whether the amount pumped is large or small. The pumping assembly which is installed for pumping an 80 bbl. well continues in use when less than one-half that amount is being pro-duced, but the cost of the operation continues practically unchanged."15 Maintaining our conservative bias however we will say that the operating costs of the remaining wells would have been increased somewhat and make the assumption that the overall saving in production costs would be nearer to $175 million. Totaling, the figure of overinvestment caused by the overdrilling of fields comes to $555 million (using the calculation above based on the CP.A. figures) plus $175 million or $730 million. - 62 -Part II: Overinvestment Due to Prorationing Itself In this section our aim is to calculate the amount of overinvestment which has been encouraged by the system of prorationing itself. Our task is to guess at how the industry would have grown in the absence of prorationing and compare the amount of investment which would have been required under this assumed system as against the amount which has actually taken place - less of course the amount which has actually taken place due to overdrilling as dis-cussed in Part I and. which is not chargeable to prorationing as such. With a system of prorationing operated under an "ideal" set of rules excess investment through the too close drilling of wells, as discussed in Part I, would not have taken place. Even so we would s t i l l be faced with the same amount of productive capacity - that is we would s t i l l have the same fields developed as now, with the same amount of recoverable reserves, the difference being that on average we would have had fewer wells drilled per field. In other words the present situation, wherein approximately one-half of the industry capacity is "shut in", would s t i l l prevail. Now assuming that prorationing had not been instituted i t seems reasonable to suppose that the industry would not have developed any appreciable amount of shut-in capacity. The tendency of existing producers in the face of new o i l "finds" would have been to lower their price i f production from these new sources would have meant that some of their - 6 3 -capacity would have to have been shut in. Even so there are reasons why we would expect that even in a system without prorationing that some shut in capacity would develop. One-reason would be that in some cases the revenue loss incurred, by the low cost producers in preventing a new producer from entering the market would be greater than the loss they would incur by allowing him "in". Consider the simple case where we have a producer with a low cost source who can produce o i l profitably at $1.50 per bbl. but because of strong demand is able to realize $2.50 / bbl. Say he supplies the total market of 50,000 b/d. A second operator now discovers a source which he feels could be developed profitably i f he could achieve as much as $2.00 per bbl. - say his field would be capable of producing 5,000 b/d. The low cost producer could prevent this newcomer's entry by lowering his price to something less than $2.00 per bbl. but in so doing - and assuming a market with a reasonably large number of buyers - he would suffer a revenue loss of 50,000 b/d x 50cents. / bbl. or $25,000 / day. Obviously i t would be cheaper for him to let the new source in and shut in 5,000 b/d of his own capacity by which tactic he would lose only 5,000 b/d x $2.50 / bbl. or $12,500 per day. We would not expect a great deal of shut in capacity to be generated in this fashion though as the low cost producer would not be willing to...suffer very much shut in capacity. Quite soon in the "game" he would find i t to his advantage to lower his price and attempt to regain f u l l production. In the example above the low cost producer would not tolerate - 64 -a shut in capacity of greater than 10,000 b/d. Another reason for some shut in capacity at any point in time is the fact that demand for crude fluctuates 16 significantly over the year so that developing enough cap-acity for peak periods might leave the producer with some over capacity at other times. And a third reason would be the producers' wish to have some immediate capacity in hand to allow them to take advantage of unexpected marketing opportunities. Over capacity to cope with monthly demand fluctuations would be a small amount - storage facilities would allow the producers to even out production to quite an extent. Capacity in hand to cope with unexpected opportunities we would also not expect to be large on the assumption (a very important one) that the industry would have a considerable amount of undeveloped, reserves on hand awaiting more favorable con-ditions for their development. In this situation a field or fields could be brought into production on fairly short notice hence making unnecessary the availability of large amounts of "contingency capacity". Our contention then is that without prorationing and assuming approximately the same type of market structure as under the present system that the industry would have develop-ed with some productive overcapacity always in hand but by no means with as much as we presently see. With no proration-ing many of the fields which are now producers would not have been developed at a l l - we hypothesize that they probably would have been found but that they would not have been - 65 -developed. Implicit in this statement is our expectation that in the absence of prorationing the price of crude o i l would be lower. Summarizing, what we have said is that even an "ideal" prorationing system - one wherein no encouragement is given to the drilling of unnecessary i n f i l l wells as described in Part I - would have led to the development of the same order of productive over capacity as in fact now exists. With no prorationing on the other hand we would expect only a small amount of over capacity to prevail. So prorationing, even i f i t does not encourage excessive i n f i l l drilling s t i l l leads to excessive development in that i t encourages - through a maintained high price - the development of high cost sources in the face of available low cost supply. Our problem then is to determine what fields would not have been developed in the absence of prorationing. We have to guess at how the industry would have grown without pro-rationing. We hypothesize as follows: 1) That the industry would have been developed by private enterprise and that the market structure would be much the same as i t has been. (An alternate hypothesis would be to assume development undertaken by the State, but we reject this as unlikely in a Canadian context.) 2) That field regulations similar to those now in force as regards granting of exploratory - 66 -permits, disposition of lease rights, setting of MPR's, etc. would s t i l l be enforced. 3) That up to December 1950 (the inception of prorationing in Alberta) the dis-covery and development of fields would have taken place as i t in fact did take place (this may not be entirely realistic as the actual development that did occur may have been influenced by the assumption that prorationing would be instituted i f "oversupply" became a problem). 4) That after 1950 new fields would have been developed only i f growth of demand required additional sources of supply. (Another reason for a field to be developed would be i f i t was so prolific that i t could be operated 17 profitably at less than the lifting costs of some of the existing fields thus forcing them out of production. However because of the difficulty of assessing when a new field might be good enough to displace a producing one we will ignore this possibility). 5) That a l l the oi l fields in Western Canada would have been discovered at the same time and in the same sequence as in fact they were. - 67 -It seems reasonable to assume that ex-ploration work would have been actively carried out even in the face of adequate present supplies as operators looked for a "find" which i f not good enough to enable them to enter the market immediately would at least give them a source which could be developed as soon as increased demand would warrant. Only the lowest cost fields of course would be developed - the others we assume would be drilled only to an extent sufficient to determine their size and then "capped" to await the coming of higher prices. That the amount of crude o i l sold would have been the same without prorationing as it has been with, and that we would be serv-ing the same markets. In view of our belief that the price of crude would be lower this amounts to saying that the elasticity of demand for crude over this period would be zero. Now this doubtless is not accurate but for our purposes of comparing develop-ment with and without prorationing i t is what we must assume. The question which we are trying to answer here is how much too - 68 -much have we spent in producing that amount of o i l which we have in fact pro-duced. We will leave to the next chapter the question of what increase in output might have been expected due to a lower price of crude. On the basis of this body of assumptions we will pro-ceed as follows to determine those o i l fields that would have been developed in the absence of prorationing. At the end of 1950 there would have been nine major fields in the 18 process of development - i t is our contention that the development of these fields would have continued and been completed. We will make the assumption that the productive capacity of these fields (and of a l l fields that we will subsequently consider) would be in the order of 8$ of their remaining recoverable reserves. (Appendices II & III show recent estimates of the original recoverable 20, reserves of a l l major o i l fields in Western Canada ). We know that at the end of 1950 these nine fields were more than enough to handle demand. Our hypothesis, in view of this, is that no other fields would have been developed until such time as the production capacity of these nine (calculated on the 8$ basis described above) became inadequate to satisfy the demand. Our procedure then is to calculate year by year (begin-ning with 1951) the remaining recoverable reserves, and hence - 69 -the producing capacity, of the producing fields. So long as this capacity in any year is great enough to satisfy the demand for crude which actually occurred in that year we contend that no further capacity would be developed. When the stage is reached where the remaining reserves of the producing fields are no longer comfortably adequate to satisfy the o i l requirements we then suppose that another field would be developed and added to the l i s t of producers. The field (or fields) added would be the one (or those) which 21 we deem as "best" from the l i s t of those that we suggest would have been discovered up to that time. Similarly when the now augmented l i s t of producing fields is again in danger of falling short of sufficient productive capacity we assume that yet another field would be developed - and so on. It should be pointed out that overinvestment in the sense that we are studying i t here has taken place in a l l of Western Canada though technically prorationing has been practiced only in Alberta. However It is clear that the high crude price maintained by the Alberta scheme applies to a l l West Canadian oi l and hence has encouraged the development of high cost sources in a l l the provinces. Consequently to arrive at a figure for overinvestment due to prorationing itself con-sideration must be given to a l l the fields in Western Canada. Therefore in following the procedure outlined above whereby we pick the "next best field" to add to our l i s t of producers as we progress from year to year, we will be considering also the merits of fields in provinces other than Alberta. In this manner we will progress to the end of 1965 at - 70 -which time we will have a complete l i s t of those fields which we claim would have been developed without pro-rationing. By then comparing this l i s t to the actual number of fields that had been developed we expose those fields developed only due to prorationing. 1950 - Original recoverable reserves of those fields discovered and partially developed by the end. 22 of 1950 = 1,950,000,000 bbls. Production from these fields 1947 to end of 23 1950: 1947 - 5,822,000 bbls. 1948 - 9,594,000 " 1949 - 18,786,000 " 1950 - 29,064,000 " Total - 63,266,000 bbls. Remaining reserves at end of 1950 = 1,950,000,000 bbls. -63,000,000 1,887,000,000 bbls. 1951 - Production capacity of developed Western Can-adian Fields = 8$ x 1,887, = 151,000,000 bbls./year = 414,000 b/d Actual production in 1951 = 44,397,000 bbls. 122,000 b/d Remaining reserves at end of 1951 = 1,887,000,000 - -44,000,000 1,843,000,000 bbls. - 71 -1952 - Production capacity = 8$ x 1,843, = 147,000,000 bbls. = 405,000 b/d. Actual production = 57,213,000 bbls 157,000 b/d Remaining reserves at end of 1952 = 1,843,000,000 bbls. -57,000,000 1,786,000,000 bbls. 1953 - Production capacity = 8$ x 1,786, = 143,000,000 bbls. 391,000 b/d. Actual production = 76,260,000 bbls 209,000 b/d. Remaining reserves end of 1953 = 1,786,000,000 bbls. -76,000,000 1,710,000,000 bbls. 1954 - Production capacity = 8$ x 1,710, = 137,000,000 bbls. = 374,000 b/d Actual production = 89,222,000 bbls. 244,000 b/d Actual production is approaching close to capacity. We assume therefore that the low cost field or fields of those discovered to this time would have been developed during this year. We hypothesize that the Daly field in Manitoba and the Wizard Lake field of Alberta would have been developed. Remaining reserves end of 1954 = 1,710,000,000 bbls. -89,000,000 1,621,000,000 bbls. Add Daly 18,000,000 Wizard Lake 240,000,000 1,879,000,000 bbls. - 72 -1955 - Production capacity = 8$ x 1,879, = 150,000,000 bbls. = 412,000 b/d Actual production = 118,481,000 bbls. 324,000 b/d Assume the Bonnie Glen field, Alta., developed this year. Remaining reserves end 1955 = 1,879,000,000 bbls. -118,000,000 1,761,000,000 bbls. Add Bonnie Glen 400,000,000 2,161,000,000 bbls. 1956 - Production capacity = 8$ x 2 , l 6 l , = 173,000,000 bbls. 475,000 b/d Actual production = 156,681,000 bbls. 430,000 b/d Fields developed - Virden-Roselea-,. Man. 17,000,000 bbls. 1956 & original North Virden-Scallion, recoverable Man. 27,000,000 bbls. reserves Westerose, Alta. 110,000,000 bbls. Weyburn, Sask. 338,000,000 bbls. 492,000,000 bbls. Remaining reserves end 1956 = 2,161,000,000 bbls. -157,000,000 2,004,000,000 bbls. Add 492,000,000 2,496,000,000 bbls. 1957 - Production capacity = 8$ x 2,496 = 200,000,000 bbls. = 547,000 b/d. Actual production = 164,989,000 bbls. 452,000 b/d Fields developed 1957 Glen Park, Alta. 17,000,000 bbls. Steelman, Sask. 215,000,000 bbls. 232,000,000 bbls. - 73 -1957 (Cont'd.) Remaining reserves end 1957 = 2,496,000,000 bbls. -165,000,000 2,331,000,000 bbls. Add 232,000,000 2,563,000,000 bbls. 1958 - Production capacity = 8% x 2,563, = 205,000,000 bbls = 563,000 b/d. Actual production = 148,303,000 bbls. 406,000 b/d. Fields developed 1958 - none Remaining reserves end 1958 = 2,563,000,000 bbls. -148,000,000 2,425,000,000 bbls. 1959 - Production capacity = 8$ x 2,425, = 194,000,000 bbls, = 532,000 b/d. Actual production = 165,976,000 bbls. 455,000 b/d. Fields developed 1959 MIdale, Sask. ' 100,000,000 bbls. Nottingham, Sask. 66,000,000 bbls. Alida, Sask. 23,000,000 bbls* 189,000,000 bbls. Remaining reserves end 1959 = 2,425,000,000 bbls. -166,000,000 2,259,000,000 bbls. Add 189,000,000 2,448,000,000 bbls. - 74 -I960 - Production capacity = 8$ x 2,448, = 196,000,000 bbls. = 537,000 b/d. Actual production = 173,482,000 bbls. 475,000 b/d. Fields developed i960 -New Norway, Alta. 8,000,000 bbls. Duhamel, Alta. 10,000,000 Bellshill Lake, Alta. 20,000,000 Hastings, Sask. 30,000,000 Queensdale, Sask. 19,000,000 Swan Hills, Alta. 800,000,000 887,000,000 bbls. Remaining reserves end i960 = 2,448,000,000 bbls. -173,000,000 2,275,000,000 bbls. Add 887,000,000 3,162,000,000 bbls. 1961 - Production capacity = 8$ x 3,162, = 253,000,000 bbls. = 695,000 b/d Actual production = 202,075,000 bbls. 555,000 b/d Fields developed 1961 -Swan Hills South, Alta 400,000,000 bbls. Remaining reserves end 196l = 3,162,000,000 bbls. - 202,000,000 2,960,000,000 bbls. Add 400,000,000 3,360,000,000 bbls. 1962 - Production capacity = 8% x 3,360, = 268,000,000 bbls. 736,000 b/d. Actual production = 222,921,000 bbls. = 610,000 b/d. - 75 -1962 (Cont'd.) F i e l d s developed 1962 -Harmatten-Elkton, A l t a . 58,000,000 b b l s . Harmatten East, A l t a . 62,000,000 St. A l b e r t - B i g Lake, A l t a . 18,000,000 Sturgeon Lake, A l t a . 22,000,000 Sturgeon Lake, South, A l t a . 145,000,000 305,000,000 b b l s . Remaining reserves end 1962 = 3,360,000,000 b b l s . -223,000,000 3,137,000,000 Add 305,000,000 3,442,000,000 b b l s . 1963 - Production c a p a c i t y = 8$ x 3,442, = 276,000,000 bbls, = 755,000 b/d. A c t u a l production = 232,663,000 b b l s . 637,000 b/d. F i e l d s developed, 1963 -Sundre, A l t a . 32,000,000 b b l s . West Drumheller, A l t a . 28,000,000 Dodsland, Sask. 29,000,000 C o l v i l l e - S m i l e y , Sask. 20,000,000 109,000,000 b b l s . Remaining reserves end 1963 = 3,442,000,000 b b l s . -233,000,000 3,209,000,000 b b l s . Add 109,000,000 3,318,000,000 b b l s . 1964 - Producing c a p a c i t y = Q% x 3,318, = 265,000,000 b b l s . = 726,000 b/d A c t u a l production = 242,910,000 b b l s . 665,000 b/d. - 76 -1964 (Cont'd.) Fields developed in 1964 -Malmo, Alta. 28,000,000 bbls. Erskine, Alta. 25,000,000 Carnduff, Sask. 35,000,000 Alameda, Sask. 15,000,000 Willmar, Sask. 18,000,000 Workman, Sask. 15,000,000 Judy Creek, Alta. 490,000,000 626,000,000 bbls. Remaining reserves end 1964 = 3,318,000,000 bbls. -243,000,000 3,075,000,000 Add 626,000,000 3,701,000,000 bbls. 1965 - Producing capacity = 8$ x 3,701, = 296,000,000 bbls, = 811,000 b/d. Actual production = 263,278,000 bbls. 722,000 b/d. Fields developed 1965 -Mitsue, Alta. 135,000,000 bbls. Lost Horse H i l l , Sask. 13,000,000 Innisfail, Alta. 66,000,000 Virginia Hills, Alta. 174,000,000 388,000,000 bbls. Remaining reserves end 1965 = 3,701,000,000 bbls. -263,000,000 3,438,000,000 Add 388,000,000 3,826,000,000 bbls. Adding up the number of wells in the fields above which we say would have been developed by the end of 1965 gives us a total of 4,130. To this number must be added 3,000 wells in fields producing low gravity crude which would have been - 77 -drilled as well. Our contention then is that in the absence of prorationing approximately 7,130 wells would have been drilled compared to the total number actually drilled of 13,900 (22,000 wells total minus the 8,100 wells already deducted as being drilled on too close spacing). Examination of the above l i s t of fields, which we claim would have been developed to the end of 1965, shows that nearly a l l of the major fields of Western Canada would have been developed. The one very important exception to this is Pembina. The remainder of the fields which according to our procedure would not have been developed are nearly a l l small fields of less than 10,000,000 barrels reserves each. It is possible of course that in some cases I have chosen wrongly in guessing which fields would have been developed. By and large though I do not feel that any other selector would have chosen much differently. The reason for assuming that Pembina would not have been developed in the face of the other fields, though con-taining more reserves than any other, is simply that is is not a "rich" field. It is its: large area which accounts for its quantity of reserves - in the very important measure however of recoverable reserves per acre i t rates very poorly compared with the others with a value of 3,770 barrels / acre In addition to this i t suffers from other disadvantages. Hanson, writing in 1957, says: - 78 -"The Pembina field has posed some pro-ducing problems which normally occur only years after a field has been in operation. The sandstone usually needs shooting treat-ment to fracture i t and increase permeability. Solution gas pressures have gone down greatly and many pumps have had to be installed. Since the o i l is high in paraffin content, waxing is a problem, and in winter the crude has to be heated for ease of transmission through pipelines. The poor permeability of the field has led operators to consider secondary recovery methods."25 Its one advantage over some of the fields that we chose in preference - principally Swan Hills, Swan Hills South, and Judy Creek - is that i t is considerably shallower at about 5,100' (compared to roughly 8,500' for the Swan Hills fields). This is certainly significant but the fact that the Swan Hills fields have required less than one-fifth as many wells to tap about the same quantity of reserves (about 1,690 million barrels in the fields mentioned) would seem to more than compensate for this factor. The other fields which we assumed would not have been developed are mostly those of small size. The reasoning here is fir s t l y that fields with low reserves are usually fields with low reserves per acre, and secondly that small fields suffer from dis-economies of small scale - principally with respect to use of surface facilities, the transportation of crude to central storage or refinery areas, and the im-plementation of pressure maintenance or secondary recovery schemes. Our contention then is that 6,770 (or 48.6$) of the - 79 -13,900 development wells remaining (after allowing for those wells already deducted as being on too close spacing) would not have been drilled in the absence of 26 prorationing. What does this represent in dollar terms? First assuming the same average depth of well (4,650') 27 as calculated in Part I, and therefore the same average cost for drilling and completing a well as we figured there - namely $71,500 - the amount of overinvestment due to excessive drilling and completion costs would be $71,500/ well x 6,770 wells or about $485 million. Secondly by not having drilled these wells investment in surface facilities (separators, tanks, etc.) would have been considerably less. It will be remembered that in Part I above we assumed that the same surface facilities would have been required even though the 8,100 wells which we considered excess there were removed. This is because in that case we were "thinning" the wells but s t i l l retaining the same number of fields producing the same amount of o i l so that we felt that roughly the same amount of surface facilities would be required. Here however the 6,770 wells that are being removed represent whole fields and therefore the surface facilities built in these fields, which would of course be removed as well, must also be considered as overinvestment. The CP.A. Statistical Year Books show that from 1947 to 1965 some $4l4 million was spent on field equipment for 28 the handling of crude o i l . This figure must be reduced however as i t includes expenditures for pumping equipment which have already been incorporated into the well costs - 80 -used above. Deducting then capital expenditures made on pumping equipment during this period we make the assumption that 1/3 of a l l development wells drilled in Western Canada would have required pumping by the end of 1965. Using a per well cost for pumps of $10,000 (above the figure used, was $5,000 on the basis of each pumping unit being used twice. In using $10,000 here the thought is that to the end of 1965 nearly a l l units would be on their first use) yields a capital expenditure figure on pumps of 1/3 x 22,000 wells x $10,000 / well or about $74 millions. Sub-tracting this from $4l4 million leaves a capital expenditure for other field equipment of $340 million. Of this amount we say that $165 million (48.6$) should not have been spent. Thirdly excess investment has occurred due to the opera-tion of these excess wells and facilities. As already noted the total amount spent to the end of 1965 in this category of expenditure is reported by the CP.A. to have been about $950 million. We have already taken $175 million of this as due to the operation of the 8,100 excess wells of Part I, thus leaving $775 million for consideration here. Referring again to the breakdown of production expense suggested by Mr. Arps (see footnote 14) we conclude that a l l operating expenses except "District expense" (or 75$ of the total) would f a l l in proportion to the number of wells here consider-ed as excess. As for "District expense" (25$ of production costs) i t seems reasonable to suggest that this would f a l l less than proportionately - we will say only by half as much. On this basis overinvestment through excessive - 81 -operating costs has amounted to 48.6$ of $580 million (75$ of $775 million) plus 24.3$ of $195 million (25$ of $775 million) or to some $330 million. Fourthly, and finally, excess expenditure has taken place due to overinvestment in pressure maintenance and secondary recovery projects. With the reduction in the number of fields the amount spent on these schemes would have been less - again we assume i t less in proportion to the number of wells which have here been considered as excess. CP.A. figures show expenditures made on this type 29 of project as being about $94 million to the end of 1965. Overinvestment then has been $46 million. Summing a l l these figures shows the total amount of overinvestment due to prorationing itself as being in the order of $1,026 million.- 5 0 Before going on to consider the significance of these overinvestment amounts (as calculated in Part I and II above) a few comments concerning their "soundness" are in order. First as regards overinvestment due to overdrilling nearly any investigator we feel given the problem of deter-mining its amount would have come up with a figure roughly equal to the $730 million above so long as he used our yard-stick - namely that anything closer than 160 acres is over-drilling. Some of course would have chosen to use another spacing as the "standard" but i t seems likely that few would have selected one less than 160 acres; also i t seems - 82 -likely that whatever the spacing selected a procedure largely corresponding to ours would have been used in cal-culating the overinvestment. Our feeling therefore is that most opinion would find the above figure a soundly based one and, i f anything conservative. One criticism may be levelled at i t though. This would be that i t is hardly fair to look back over 20 years of o i l -field development with the knowledge and technology that we now possess and on this basis declare that "We sure wasted a lot of money In the old days". It would be just as sensible, a critic might say, to suggest that there has been a tremen-dous amount of waste in the Canadian steel industry because certainly our present methods of making steel and steel products are much tfiore efficient than the old. This criticism is valid to the extent that in 194-7 and thereafter the con-sensus was that spacing at 4-0 acres (and in Saskatchewan 80 acres) was in fact "best". Certainly based, on North American experience this spacing policy was at the time an enlightened one - whether technological information was available which should, have suggested to the O.G.C.B. and others that even wider spacing was desireable is speculation. Therefore whereas we feel that the $730 million figure remains a con-servative one as to the total amount of overinvestment which took place as a result of overdrilling i t is certainly argu-able as to what portion, of this amount could fairly be class-ed as avoidable overinvestment. This is a very important point and the reader should keep i t firmly in mind when in the chapter following consideration is given to the - 83 -consequences that this over-expenditure has had on the price of crude. As to the merits of the overinvestment figure due to prorationing itself the situation is somewhat the reverse of that above. Here we claim that there might reasonably be dispute with our amount but not with the fact that this type of overinvestment is fairly classed as such in the sense that i t was avoidable. Arriving at an overinvestment amount due to prorationing itself requires that one construct a "what might have been" situation, and whereas we think that the process of development which we have outlined above is a reasonable one, we acknowledge that not everyone might think so. It remains to the reader therefore to make up his own mind as to the correctness of the procedure that we have followed and to weigh the con-clusions reached in Chapters IV and V in the light of his decision. In insisting that, whatever the amount, this type of overinvestment can fairly be labelled overinvestment, we are expressing our belief that in 1950 just as clearly as now prorationing should have been recognized as poor policy - there is no excuse here that this is not over-investment because in 1950 we just didn't know any better. Just one further comment - in connection with the procedure here used to determine the overinvestment due to prorationing i t would not be surprising to learn that the most common objection to my "model" is to the assumption in i t that exploration would have continued at the same pace as under prorationing. One so often hears i t expressed that - 84 -without the prorationing system and as a consequence of the necessarily lower price for crude that exploration effort would diminish because profits would be less. This argument assumes that lower prices mean lower profits -that this should be so is certainly not obvious on a priori grounds. If an operator receives $2.00 / bbl. for his o i l instead of $2.50 / bbl. and i f attthe lower price he is able to produce twice as much per day from his wells does i t necessarily follow that his profits - and hence presumably his incentive to explore - will be less? It seems not. In fact what does seem reasonable is that without prorationing profits would be at least as high (which is not saying much) 31 as with. - 85 -CHAPTER III FOOTNOTES III - 1. A "blow-out" tends to occur when a reservoir formation is penetrated which contains o i l or gas under high pressure. This is con-trolled by the blow-out preventor assembly which is attached, to the top of the surface casing. This assembly through which the d r i l l stem runs, consists of a system of valves and chokes which, at the f i r s t sign of pressure increase in the well, may be quickly shut off. For more details see Shell International Petroleum Company Limited, The Petroleum Handbook, London, 1959, PP. 77 f f . 2. See Dynamic Decade, pp. 138 to 142 3. Although not specifically stated we assume his figures are for the year 1956 or there-abouts. He does imply that the costs which he uses are representative of the period 194-7 to 1956 - the period in which most of the excess development wells which are our concern were in fact d r i l l e d . 4. This i s not truly a cost that is fixed with depth as the deeper the well that has to be dri l l e d the more expensive is the r i g set up due to more and. heavier equipment being required. 5. D r i l l i n g costs particularly increase in more than proportion, to depth for the reason that the pulling out and running in of the d r i l l stem in order to change bits becomes pro-gressively more time consuming the deeper the well gets. Also i t i s often the case that as the well gets deeper the formations to be dr i l l e d through become harder resulting in the need to;change bits more frequently than for a shallow hole. 6. See A. S. Murray, "Recent Trends in Canadian Dr i l l i n g Practices", Canadian Oil & Gas  Industries, February 1954, pp. 45 to 49. This article suggests from two penetration rate studies, one in the Leduc f i e l d and the other in the Acheson f i e l d , that d r i l l i n g costs rise at a much greater rate after 4,000'. In the fields considered this Is due not only to the depth factor but also to the fact that after 3,500' much harder material is encountered. - 86 -I I I - 7. See O i l arid Gas J o u r n a l , October 6, 1958, p.172, Oct. 12, 1959, P.134, and September 26, I960, p.193. 8. O i l and Gas J o u r n a l , October 6, 1958, p.172. 9. Canadian Petroleum A s s o c i a t i o n , S t a t i s t i c a l  Year Book, 1965, p.49 and 1962, p73T. 10. Hanson, o p . c i t . , p.l40. 11. See Appendix V I I . 12. The Pembina f i e l d f o r one f a l l s i n t o t h i s category. 13. Canadian Petroleum A s s o c i a t i o n , l o c . c i t . 14. T. C. P r i c k , ed., Petroleum Production Handbook, "Valuation of O i l and Gas Reserves'", pp.^«-22 to 38-25. Mr. Arps suggests that production costs f o r an e n t i r e f i e l d or d i s t r i c t would break down as f o l l o w s : Labor 20$ to 30$ Repairs and Maintenance 30$ to 50$ Power, waste d i s p o s a l and o i l t r e a t i n g 5$ to 15$ 4) D i s t r i c t expense 20$ to 30$ D i s t r i c t expenses r e f e r to the expenses of the d i s t r i c t o f f i c e or o r g a n i z a t i o n and i n c l u d e s u p e r v i s i o n , engineering, accounting, time-keeping, e t c . ( a l l at the d i s t r i c t l e v e l ) . Using the median value of each of the above ranges we p o s t u l a t e as f o l l o w s : - that 3/4 of the categories l ) and 2) are chargeable to the w e l l ( i n other words about 50$ of t o t a l cost -i . e . 3/4 x (25$ +: 40$)), that 1/2 of category 3) i s chargeable to the w e l l (about 5$ of t o t a l c o s t ) , and that " D i s t r i c t expense" would be reduced only a small amount due to fewer w e l l s per f i e l d being d r i l l e d (due to 8,100 fewer w e l l s being d r i l l e d we would expect D i s t r i c t expense to decrease by not more than 20$ -i . e . about 5$ of t o t a l c o s t ) . This means that f o r our purposes 60$ of the operating costs may be considered to be i n -curred by the w e l l s d i r e c t l y . 15. Op. c i t . , p. 38-22 - 87 -III - 16. In January 1965 the average daily production of crude o i l for Western Canada was 850,331 ^barrels - for May of the same year i t was 716,497 barrels. Canadian Petroleum Association, Statistical Year Book, 1965, p. 29 17. Any return over marginal cost would be prefer-rable to an operator to shutting down, even though this return was nowhere near to paying out fixed costs. 18. See Appendix II. 19. Hanson, op. cit., p. 124 states that pools can seldom be produced at an annual rate above 12$ and often at no more than 6$ or 8$. We use the 8$ rate as i t jibes well with the oft heard statistic that a country must maintain reserves at least 12 times actual production i f i t hopes to remain self sufficient in supply. 20. Reserve estimates are continually subject to change as more field information is gathered, as recovery technology advances, and as secondary recovery schemes are put into effect. At the times that these fields were discovered the reserves which they were thought to contain would have been considerably less than these figures. Notwithstanding, this is the amount of recoverable o i l that these sources in fact contained - whether or not i t was realized at the time i t would have become evident as development progressed. One fact that might be significant, though we do not consider i t in what follows, is that under the assumption that the price of crude would have been lower without prorationing less of these reserves would have been economically recoverable. 21. By "best" we of course mean the field that we feel would be the lowest cost producer of those discovered (but not producing) to that time. In arriving at a "best" from any group of fields we consider such information as location of the field, depth to pay zone, recoverable reserves per acre, type and effectiveness of reservoir "drive", MPR's alloted to the fields, gravity of crude, and any other data which would reflect on how profitable production from a field is likely to be. - 88 -III - 22. A l l reserve figures shown In the following calculations are to be found i n Appendices II and I I I . 23. Actual production of crude o i l (in the l i g h t and medium crude o i l category) year by year i s given i n Appendix VIII. 24. The recoverable reserves figure which we have used f o r Pembina i s 1,600 m i l l i o n barrels (see Appendix I I I ) . The approxi-mate developed producing area of this f i e l d i s 423,000 acres (see P r i n c i p a l O i l  Fields i n Alberta, Canadian Imperial Bank Commerce, Calgary, September, 1966). This y i e l d s a reserves per acre figure of 3,770 bar r e l s . 25. Hanson, op. c i t . , pp. 104 and 105 26. Had Pembina been included i n the l i s t of developed f i e l d s and some others with approximately the same quantity of reserves l e f t out t h i s r e s u l t would be s i g n i f i c a n t l y d i f f e r e n t . This bears pointing out f o r the benefit of any reader who f e e l s just as strongly that Pembina, would have been develop-ed as I f e e l that i t would not have been. Pembina's development would probably come at the expense of the f i e l d s i n the Swan H i l l s area about 110 miles north-west of Edmonton. The reserves of these f i e l d s (Swan H i l l s , Swan H i l l s South, and Judy Creek) at some 1,690 m i l l i o n barrels are about the same as Pembina's. The addition of Pembina would have added 2,820 development wells*, removing Swan H i l l s et a l . would have reduced the number by 580. The t o t a l number of develop-ment wells under t h i s scheme then would have been 2,240 more than the 7,130 calculated above, or 9,370. The number of excess develop-ment wells would have been 4,530 or about 30$ of the t o t a l (rather than 48.6$ as above). 27. If they are the same average depth why are these high cost sources? Recall that the f i e l d s assumed as not developed were those which were considered would be high cost not so much be-cause of the expense of developing them due to depth, access, etc., but because of t h e i r low productivity and/or operating i n e f f i c i e n c y . - 89 -27. (Cont'd.) It is reasonable to assume that the depths of wells in these fields would be about the same average as the depth of a l l . 28. Canadian Petroleum Association, Statistical  Year Book, 1965 p.49 and 1962 p.W. 29. Loc. cit. 30. Following footnote 26, and assuming Pembina had been developed and Swan Hills et al. had not been, the final figure for overinvest-ment here would have been in the order of $660 million. 31. See Appendix IX suggesting that the rate of return and hence exploration could be same, even at lower price. - 90 -CHAPTER IV THE SIGNIFICANCE OF THE OVERINVESTMENT The total amount of excess expenditure then which we calculate has taken place amounts to some $730 million due to overdrilling, plus approximately $1,000 million due to prorationing itself. The aim of this chapter is to con-sider how much lower the price of Canadian crude could have been had this expenditure not taken place, and. what the significance of this lower price might have been. First considering the $730 million excess outlay due to overdrilling we assume that this kind of overexpenditure occurred equiproportionately in a l l fields - that is we assume that the proportion of"overdrilling" expense to total expense incurred by the marginal or high cost fields was, on average, the same as that incurred by low cost fields - or any others in between. Under this assumption and following the reasoning that a $1,000 investment requires only one half the dollar return that a $2,000 investment does i t can be said that the wellhead price of crude at the end of 1965, could have been lower by the proportion that $730 million bears to the total expenditures that had been made. Had the overdrilling not taken place the same quantity of recoverable reserves and. the same "MPR" producing capacity would have prevailed - overdrilling just means that more money than necessary has been spent to develop exactly the same resource to exactly the same degree. Therefore i t is entirely - 91 -reasonable to say that the price could have been lower in the same proportion that outlays on overdrilling were to total outlays. We are interested then in determining the total of expenditures (both capital and operating) made to the end of 1965 in developing Western Canada's productive capacity of crude o i l . Of interest will be a l l expenditures made in making possible the production of crude o i l at the "well-head" (meaning a treated saleable product at the field gathering station). By referring to industry expenditure statistics as published annually by the Canadian Petroleum Association we arrive at a sum spent on exploration, develop-ment, production, and administration of $7,417 million, (for the period 19^7 to 1965 inclusive). 1 This figure excludes those expenditures explicitly shown to be chargeable to the development or processing of natural gas. It also excludes royalty and ad valorum tax payments - while these are an industry expense i t is our assumption that they would be levied at the same percentage rates even thought the price of crude was lower and that therefore they would f a l l in the same proportion as the price of crude could have had the overdrilling not taken place. Therefore i t will not affect the result i f we leave these out of account. What must be added though is the investment that has been made in crude oi l "gathering lines" (pipe lines which collect treated crude from a l l the field storage tanks and deliver i t to a central gathering station or to a "trunk" pipe line). The CP.A. does not record expenditure amounts for pipelines - 92 -but they doe reveal that to the end of 1965 about 4,500 miles of gathering lines were built in Western Canada. Using 5,000 miles as a conservative estimate and a per mile cost figure for this type of line (mainly y" to 6") 3 of $30,000 yields an amount of $150 million. Added to the $7,4l7 above this gives a total expenditure figure of $7,567 million - let us use $7,600 million. We can conclude therefore that had the $730 million outlay or excess wells due to overdrilling not taken place that the price of crude oi l at the end of 1965 could have been lower by $730 million $7,600 m i l l i o n or 9.6$. Secondly what has been the impact on price of the $1,000 million spent in developing high cost fields? The answer to this cannot be arrived at in so straight forward a manner as was followed above - i t cannot be said here that i f this expenditure had not taken place that the price of crude could have been lower by a proportionate amount. This is because the cost of producing crude from the fields remain-ing after elimination of the high cost fields bears no particular relationship to the amount spent in developing and producing the high cost fields. If we knew what the cost of producing crude from each field was our task would be an easy one - referring to the model developed in the last chapter we would pick the high cost field from those which we assumed would be developed and simply declare that the price of crude would be the cost of producing from this marginal field. Unfortunately this kind of cost information is not available so our approach - 93 -must be a different one. There are three reasons for expecting the price of crude would have been lower had the high cost fields not been drilled. First, and assuming just for the moment that the fields' remaining after the high cost ones had been removed s t i l l produced at approximately one-half their 4 capacity, the price would have been lower because the cost of producing from the "new" high cost field would now be lower - that is the marginal field would be a lower cost field than previously. However we know, of course, that the remaining fields would not have produced at one-half cap-acity output but rather at nearly f u l l capacity - which would give rise to the second and third reasons for lower price. Second that the operating costs of the remaining fields would increase in less than proportion to output -doubling the output from the existing wells would increase but l i t t l e the total operating costs -. and third that the faster rate of production per field would allow the producer a faster payout; so that the capital cost per barrel would be lower also. In considering the importance of this last reason however i t must be kept in mind that the capital cost per producing field would be greater than previously due to exploration expenses (which we assumed would be the same as under prorationing) now being borne by fewer fields. So we know that the price of crude could have been lower had the high cost fields not been drilled. The question is how much lower? The cost of producing crude from the marginal fields today must be in the $2.50 to $2.75 / bbl. range which - 94 -is the top wellhead price range received by crudes in the light and medium gravity categories. Let us use a price of $2.75 then as the cost of producing from the marginal field. The cost of producing from low cost fields (which i t is to be remembered operate at about half capacity) we do not know. Our guess would be that fields such as Golden Spike, Wizard Lake, and Bonnie Glen (which would be among the lowest cost fields) would cost no more than $1.50 / bbl. to produce. To be conservative however we will assume a figures of $2.00 / bbl. - this must be conservative as fields in northern B.C. producing 40 - crude receive a wellhead price of approximately $2.15 / bbl. (because of their remote location) and are nowhere near to being the "producers" that are those mentioned above and some others. We assume a present cost range for a l l fields then from a bottom price of $2.00 / bbl. to a top of $2.75 / bbl. But above we have established that the cost of producing from these fields i f overdrilling had not occurred would be 9.6$ lower than this. The cost range without overdrilling there-fore would have been $1 .8 l to $2.48 / bbl. Now at the end of 1965 approximately 225 fields in the light and medium gravity categories were producing in Western Canada. According to our model had prorationing not pre-vailed this number would have been reduced by about three quarters to 59. It seems safe to conclude therefore that had the high cost fields not been developed that the cost of producing from the "new" marginal field ( s t i l l at one-half - 95 -capacity) would not have been more than half way up the spread from $1.81 to $2.48 / bbl. - i.e. i t would not have been more than $2.15 / bbl. Using this figure of $2.15 / bbl. the question now is how much further could the cost have been reduced as a result of the efficiencies gained through these fields producing at nearly f u l l capacity. As regards operating costs i t will be recalled that in Chapter III the con-clusion was reached (p. 6l) that a doubling of output from existing wells would increase operating costs by only a small amount. Some increase however would be expected so we will be generous and assume the total increase would be in the proportion of one-half the increase in output. It is clear that the effect of this would be that operating costs per  barrel would be reduced to three quarters i f output were doubled. Referring to CP.A. statistics average operating cost per barrel have consistently been in the $0.35 to $0.40 7 range. As we are here dealing with the lower cost fields we will use the $0.35 / bbl. figure as being representative of their operating costs. Doubling the output of these fields then would have meant that operating costs would have been reduced to-at least 3/4 x $0.35 / bbl. or $0.26 / bbl. This would have reduced the cost of producing from the marginal field from $2.15 / bbl. to $2.06 / bbl. Now what about reduced capital costs? As pointed out above these would be lower also due to a faster payout as the fields produced at f u l l capacity. No reduction could be expected though with respect to that part of capital - 96 -8 invested in "exploration". This is because of our assumptions that without prorationing exploration ex-penditures would have been the same and total output would, have been the same - i t is reasonable to expect therefore that the required recovery of exploration costs per barrel would have been the same as i t is now, so long as we assume (which we do) that the same proportion of total exploration costs would have been incurred by producers with operating fields as in fact has been the case. We have contended that had prorationing not been im-N plemented and had the overdrilling of fields not taken place that total outlays on those fields which we claim would have been developed would not have exceeded $5,870 million. ($7,600 million - $730 million - $1,000 million). Deducting • Q - • operating expenditures of $445 million from this means that capital expenditures would have been $5,425 million. Of this amount "exploration" expenditures would, have amounted very closely to $4,000 million.'1'^ Capital expenditures therefore on field development would, under our scheme, have been about $1,425 million. With the fields operating at f u l l capacity each field's share of this latter amount would have been paid out twice as fast as in fact i t has been - what saving then in per barrel costs would this have meant? In order to calculate this assumptions must be made regarding the producing rates of the fields under consideration, the " l i f e " of the fields, and the rate of return required by the producers. These assumptions will be as follows: - 97 -(a) for fields producing at one-half capacity (as under pro-rationing) the annual rate of production is 4$ of each field's total remaining reserves; the li f e of each field is 20 years; and the required rate of return to capital is 10$. (b) for fields producing at f u l l capacity (as in our model) the annual rate of production is 8$ of each field's total re-maining reserves; the l i f e of each field is 10 years; and the required rate of return to capital is 10$. Referring to Table 4-1 i t is seen that under these assumptions the present value of the recoverable crude from * (267,000 bbls.) a "20 year" field is only 72$ (370,000 bbls.) of the present value of the same resource i f produced in 10 years. It is clear therefore that the capital cost per barrel of crude produced from the 10 year field would be 72$ of the capital cost of crude produced from the 20 year field. What further price reduction would this have allowed in the price of a barrel of crude? Above we have reduced the cost of producing from the marginal field to $2.06 / bbl. Of this amount $0.26 is a result of operating costs. Of the remaining $1.80 / bbl., and anticipating a final price figure of about $2.00 / bbl., the royalty payments and ad valorum taxes payable would be $0.32 / bbl. (at the present - 98 -Table 4-1 Present Value of Crude Oil Reserve Produced at 10 years and at 20 years. Rate of Discount 10$ (In bbls. x 1,000) (considering a field of 1,000,000 bbls. total reserves) Field Produced in 10 yrs. (at 8$ Rate)  Field Produced in 20 yrs. (at 4$ Rate)  Year Output/yr. PiV. of Output Ou,,tput/yr. P.V-i of Output 1 80 2 74 3 08 4 62 5 57 6 53 7 49 8 45 9 4 l 10 38 Totals 5"57 11 12 13 14 15 16 17 18 19 20 P 61 51 42 35 30 25 21 17 15 370-Totals 40 38 37 35 34 33 31 30 29 28 27 25 24 23 23 22 21 20 19 19 558" 36 31 28 24 21 19 16 14 12 11 9 8 7 6 6 5 4 4 3 3 2oT 11 average rate of about 16$). The remainder of $1.48 / bbl. would be capital cost. It will be recalled however that the proportion of capital expenditures whose cost we have suggested would be reduced by the fields operating at f u l l capacity is only 26.3$ of the total - i.e. $1,425 million ^  5,425 million Now 26.3$ of $1.48 / bbl is $0.39 / bbl. - i t is this portion of capital cost which we claim could have been reduced to - 99 -72$ had the fields produced at f u l l capacity. That is capital cost would have been reduced by $0.11 / bbl. Finally then we say that in the absence of pro-rationing and poor field regulations which have resulted in overdrilling that the cost of producing high gravity crude from marginal field (i.e. the price) would have been no more than $1.95 / bbl. ($2.06 / bbl. - $0.11 / bbl.) In fact because of our consistently conservative bias; i t might well have been less. Implicit in this last 11 cents / bbl. reduction in the cost of production from the marginal field is the assumption that the proportion of exploration expense to other capital expenses Is the same for the marginal field as i t is in total. What might this lower price have meant in terms of greater markets for Canadian oil? First, what about Eastern Canada? It will be recalled that Quebec province and the Atlantic provinces import their crude from Middle East and Venezuela sources - in 1965 an average of 400,000 b/d of which 290,000 b/d was delivered to the Montreal area and refined there. Could the lower price suggested above have captured this market for Canadian crude? Considering for the moment the Montreal area only the price of Canadian high gravity crude in Montreal would have been $1.95 / bbl., 13 plus a pipeline tariff of about $0.70 /bbl.-> plus an allowance for new storage facilities and some modifications necessary to the Montreal refineries to enable them to handle - 100 -14 the somewhat different Canadian crude; let us say a total of $2.70 / bbl. What of foreign crude? - M. A. Adelman reports that Middle East crude (of about 35 A.P.I, gravity -which would be roughly comparable to the gravity of the crude whose price we have determined above as $1.95 / bbl. wellhead) which in 1965 was posted at $1.80 / bbl. f.o.b. the Persian Gulf port of Ras Tanura was in fact selling at 15 $1.40 / bbl. - and in some cases less. Oil tanker charter rates in 1965 from Ras Tanura to Portland, Maine were A. r , 1 6 approximately $0.63 / bbl. The pipeline from Portland, Maine (the bulk of crude imported to Montreal is trans-shipped from ocean tankers at Portland via this pipeline to Montreal) to Montreal is 236 miles long - using a pipeline tariff of $0,045 / bbl. per 100 miles would add another $0.11 17 / bbl. to the price. Summing, the f.o.b. Montreal price of Middle East crude in 1965 then could have been in the order of $2.14 / bbl. - some $0.56 / bbl. less than the figure calculated above for Canadian high gravity crude. From this i t can be concluded, that the Montreal market (and even more so therefore the Atlantic provinces' market) is no place for Canadian o i l , even at the lower price that would have been possible without prorationing. S t i l l , though not capable of displacing foreign crude in Eastern Canada a lower price of Canadian o i l could have effected a lower price of "finished" products in this area. Had the price of Canadian crude been lower by $0.80 / bbl. ($2.75 / bbl. minus $1.95 / bbl.) and this reduction been reflected in lower prices for gasolines, diesel fuel, etc., - 101 -in those areas served by Canadian crude this would have forced down the prices in Eastern Canada markets as well due to the threat of arbitrage. In 1965 alone the savings to consumers in Eastern Canada through lower product prices could have been $116,500,000' (400,000 bbls./day x $0.80 / bbl. x 365 days). Would the lower price of Canadian crude have fostered increased sales in the northern part of the U.S. mid-west? This seems doubtful. The U.S. does not buy oi l on a price basis - her policy is to encourage the development of domestic sources and towards that end she imposes import quotas on foreign supplies, notwithstanding the substantial price advantage that foreign crude would have in many U.S. areas. Canadian o i l even now commands a price advantage over U.S. crude in the north central and north mid-western states yet informal restrictions are maintained on the amounts which these areas may import. Admittedly a lower Canadian price would have been an important weapon in Canada's continuing battle for a larger share of this market but even so i t seems likely that no great progress would have been made in breaching the U.S. quota barrier. Another U.S. market possibility would have been expansion of Canada's sales to the West Coast - not on the basis of a larger allowed quota by the U.S. but on the basis of displacing crude imported by that area from other sources. At the end of 1963 imports to the West Coast were:: from'.Ganada 124,300 b/d, from Indonesia 54,800 b/d, from Iran 42,300 b/d, - 102 -from Venezuela 40,000 b/d, and from Saudi Arabia . . . . 18 32,400b/d. Considering the northern Washington area where Canadian crude is most competitive, the Canadian price could have been $2.35 / bbl., assuming the well-head figure of $1.95 / bbl. plus a pipeline tariff of $0.40 / 19 bbl. The price of the cheapest foreign crude (from the Middle East) on the other hand could be delivered, for about i , 20 $2.10 / bbl. No displacement of foreign o i l in the West Coast area would have been likely by a lower Canadian price. In fact i t is obvious that the only reason that Canadian crude serves the Washington refineries now is due to the U.S. preference that (for defence reasons) this area be served, by a source which does not involve ocean transportation As regards any other world markets i t is clear from the above figures that these could be more cheaply supplied by other sources, even assuming the Canadian price would have been lower. The only remaining possible increase In sales would have been from a "deepening" of our own Canadian markets through the price elasticity of demand for crude o i l products. In conclusion then i t appears the main benefit of a lower crude price would have been to the domestic consumer through lower prices for petroleum products. These lower prices would have extended to Eastern Canada (Quebec and the Atlantic provinces) though this region continued to receive its crude from foreign sources. It does not appear that a lower price would have significantly enlarged the markets served by Canadian crude. - 103 -In the analysis above we have been careful to say that the price of Canadian crude could have been lower had prorationing and poor field regulations not prevailed. In the face of our conclusion that such lower price likely would not have led to significantly greater markets for Canadian o i l the question virtually asks itself "Would the price have been as much lower as we suggest i t could have been?" The answer likely is "no". The price may have been somewhat lower than i t is now (even this is not certain)but assuming the price elasticity of domestic demand to be low i t Is probable that much of the possible reduction would have been "sopped up" by increased rents paid by oil producers to governments - these would, have been in the form of increased royalty payments and in-creased payments for lease rights. S t i l l , better the high price be due to rents payable to government than due to cost items as a result of waste,- at least payments to government are "returned" to the people (though admittedly in this case i t is only a very few of the people - i.e. principally Albertans). Had. the price remained at present levels due to increased "rents" i t follows that the savings which we said would accrue to Eastern Canadian consumers through lower product, prices ,($116 million in 1965) would not have materialized. - 104 -CHAPTER IV - FOOTNOTES 1. Canadian Petroleum Association, Statistical Year Book, 1961, p. 39 and 1965, p. 49, Calgary, Alberta. 2. Ibid., 1965, P P . 69 - 77 3. From cost information shown in the CP.A. Statistical  Year Book, 1965, PP. 69 - 77, figures ranging from about $15,000 /mile to $33,000 / mile can be cal-culated for lines in the 2" to 8" size range. A figure in the order of $25,000 / mile is most common -we use $30,000 / mile to be conservative. 4. We saw in Chapter I, p. 11, that at the end. of 1950 when prorationing began that shut-in capacity in Western Canada was about 50$ of total capacity; similarly we saw that at the end. of 1965 i t was also very close to 50$. Though the years in between these two dates have seen some fluctuations in the percentage amount of shut-in capacity - sometimes more than 50$, sometimes less - i t has nearly always remained, relatively close to this 50$ figure. See The Royal Bank of Canada, Industry Statistics, Calgary Alta., and O.G.C.B., Oil and Gas Industry, 1962, p.5. 5. CP. A., Statistical Year Book, 1965, p. 39. 6. The Financial Post, Survey of Oils, 1966, pp. 23 - 31. 7. Dividing the expenditure figure shown annually by the CP.A. under the category "Operation of Wells" by the number of barrels of crude produced in each year results in figures which are consistently between $0.35 / bbl. and $0.40 / bbl. 8. By "exploration" expenditures we mean a l l expenditures shown under this classification by the CP.A. except for those under the category "Exploratory Drilling -Productive - Gas/Condensate". 9. Total operating expenditures i t will be recalled have been $950 million ( p. 60 Ch. III). Of this amount we assumed that $175 million (p. 6 l , Ch. I l l ) was incurred by the 8,100 wells which we considered as being excess due to being on too close spacing, and that $330 million (p. 81, Ch. I l l ) was incurred by wells and facilities developed in high cost fields. This leaves $445 million then as being the operating expenses chargeable to the fields which are tinder consideration here. - 105 -IV - 10. CP.A., Statistical Year Book, 1965, p.49 and 1961, p. 39. It is to be noted that the CP.A. includes under "Exploration" expendi-tures payments made for a l l "Land Acquisitions and Rentals". We have assumed in Chapter III that under our model expenditures on land would be $380 million less than this. However this reduction does not enable a proportionate reduction in price but is necessary to encourage the amount of exploration required i f price is to be maintained at the $1.95 level. See Appendix IX. 11. The Royal Bank of Canada, Royalty Payments to the Crown, Bulletin No. 11, February 15, m 12. CP.A., Statistical Year Book 1965, p. 37. This shows imports in 1905 from the M.E., Venezuela, and Trinidad of nearly 400,000 b/d. Of this 290,000 b/d was delivered to Quebec refineries and the remainder to refineries in the Atlantic Provinces. 13. Canada, Royal Commission on Energy, Second  Report, July 1959, PP. 5-18 to 5-23. Canadian Bechtel Limited, at the request of the Commission, prepared a study of alternative methods of trans-porting Canadian crude o i l to Montreal by pipe line. Two basic transportation methods were con-sidered: a new direct line and an expanded Inter-provincial pipe line system. Depending on the route followed and the throughput assumed the cost figures calculated varied - on the most reasonable assumptions however the cost / bbl. worked out to be in the order of $0.70 / bbl. 14 Ibid., P. 5-34 15. M. A. Adelman, "Efficiency of Resource Use in Crude Petroleum", Southern Economics Journal, October 1964, p.109 16. Oil tanker charter rates in 1965 ranged from Intascale minus 52$ (for smaller tankers) to Intascale minus 73$ (for supertankers) with Intascale from Ras Tanura to Portland, Maine, being in the order of $8.15 / long ton (a long ton of 35° A.P.I, gravity crude being equivalent to about 7.3 barrels). Using a rate of Intascale minus 55$ would then give a figure of $3.67 / long ton. To this however must be added a Suez canal tariff - 106 -IV - 16. (Cont'd.) of $0.88/ long ton for a total of $4.55 / long ton - roughly equivalent to $0.63 / bbl. (Information on Intascale rates and Suez tariff obtained from Professor P. G. Bradley, U.B.C. ) 17. U.S. Dept. of the Interior, An Appraisal of  the Petroleum Industry of the United States, January 1955, Table bl. 18. The Oil and Gas Journal, March 9, 1964, p. 54 19. CP.A., Statistical Year Book, 1965, p.105. 20. Intascale from the port of Ras Tanura to the U.S. West Coast in 1965 was in the order of $10.68 / long ton. Using as before a rate of Intascale minus 55$ would yield a figure of $4.80 / long ton or about $0.66 / bbl. Rounding this to $0.70 / bbl. to include unloading charges and adding this to the f.o.b. Ras Tanura price of $1.40 / bbl. then gives a West Coast price of $2.10 / bbl. (intascale rate obtained from Professor P. G. Bradley, U.B.C. ) 21. Canada, The Royal Commission on Energy, Second Report, p. 3-3 - 10 7 -CHAPTER V CONCLUSIONS AND RECOMMENDATIONS This study has shown that a serious amount of economic waste has taken place in the development of Canada's o i l resource due to prorationing itself, due to the regulations through which prorationing has been instituted, and due to other regulations outside of the prorationing scheme. What are the prospects for the future? Insofar as the prorationing regulations are concerned we concluded in Chapter III that the changes made to these regulations as a result of the 1963-64 O.G.C.B. hearings were very desireable ones indeed which will go a long way towards eliminating them as a source of future over-investment . As for those regulations outside of the prorationing scheme our main criticism was the retention of the system of lease disposition whereby the provincial governments ensure that lease rights are fragmented into small areas and Held by separate owners. This system obviously is not conducive to the most efficient development of an o i l pool, neither in drilling the pool nor, later, in instituting pressure maintenance or secondary recovery schemes. This policy which reflects the concern of provincial governments to ensure the widespread ownership of mineral lands, while not defensible on economic efficiency grounds, is without question a tenable one - certainly i t can be argued that "free enterprise" is best fostered by such a scheme and that this aim must take ^precedence over that of economic - 108 -efficiency. Accepting this position as a valid one though need not lead to such large sacrifices being made in operating efficiency as in fact have occurred - what should have been done and what s t i l l is required is that in conjunction with this idea of multi-ownership, legislation be passed, requiring the compulsory "unitization" of o i l pools. Com-pulsory unitization would require the bringing together of the separately owned tracts covering a pool so that an ' overall most efficient program of development and production could be carried, out - this would be done by a single or co-ordinated management set up by the lease owners as part of the unitization agreement. Costs and proceeds of pro-duction under such a system would be divided on a basis reflecting the share that each lease holder had in the pool. It would be desireable that the unitization of pools be made mandatory as soon as the outlines and ownership of a pool have been determined so that benefits could be achieved not only in efficiency gained in pressure maintenance, secondary recovery, and other operating schemes but also through the best spacing of input and production wells. If unitization is implemented soon enough the location of these wells could be determined in accordance with best engineering knowledge and without regard to lease or property lines. Desireable as i t sounds unitization to be widely practiced must be complusory. It is an operation that requires the participation of a l l parties having an interest - 109 -in the pool and without compulsion such unanimity is hard to achieve - this may be becuase of the temptation a minority party would have to hold up the agreement in order to exact an unfair advantage from the other participants, or because of a real belief that a party might have that they could do better for themselves outside of such a scheme. We would recommend, that complusory unitization legisla-tion apply retroactively as well to any situations which, though already developed, could be seen to gain from such an agreement. It is not Implied that compulsory unitization would be easy to legislate and that the reason i t hasn't been is mere oversight on somebody's part. The problems in coming up with a workable scheme must be great or why else do we see so l i t t l e of i t practiced when the benefits to be gained have been enormous. S t i l l , difficult as i t might be the gains to be made from such action are too great for i t not to be done. The various provincial governments have created the problem through their belief in the primary importance of multi-ownership - i t should be their responsibility to alleviate as far as possible the inefficiencies inherent in such a policy by the drafting of suitable complusory unitiza-tion legislation Finally what about prorationing itself? In my opinion this is clearly too wasteful a practice to be continued. The question is how do we get out of it? The hope that we will grow out of i t - that demand will increase to the point where prorationing will no longer be necessary is a very poor hope - 110 -indeed. Prorationing propagates the need for proration-ing - new operators have an incentive to develop new reserves in the knowledge that they will receive a share of the market should, they be successful; and those producers who already own a great deal of shut-in capacity must also d r i l l and develop new areas i f they are to maintain their share of the market. This inevitably leads to shut-in capacity. It is no accident or mere coincidence that from 1950 to the present time shut-in capacity has remained, at roughly 50$ of total capacity. So we are not likely to grow out of the need for prorationing - i f we are to get out at a l l definite and positive action is required. My idea of a solution is this - the Alberta government (and the other provincial governments as well, i f their co-operation could be received) must put a freeze on any further field development work until such time as demand approaches producing capacity. When this point is reached prorationing would be discontinued on the firm understanding that under no circumstances would i t be started again. The transition period of at least four or five years that this procedure would afford would allow operators to adjust for that time when they would "be on their own". Those who would best benefit from this period of grace would be mainly the small operators who under prorationing have had no incentive to develop any marketing outlets or refinery capacity of their own. Had prorationing and poor field regulations never been implemented our contention has been that the cost of a barrel - I l l -of crude in 1965 could have been $0.80 / bbl. less. Had this been transmitted to the consumer in terms of lower product prices his saving in 1965 alone would have been nearly $300 million (based on 1965 average daily consumption of crude in Canada of 1,000,000 b/d.)! We have seen that the largest part of this has been as a result of proration-ing itself. It seems inconceivable then that the practice should, be allowed to continue. Yet i t probably will. - 112 -BIBLIOGRAPHY Adelman, M.A. "Efficiency of Resource Use in Crude Petroleum". Southern Economic Journal, vol. 31 (October 1964)1 . The Supply and Price of Natural Gas. Supplement to The Journal of Industrial Economics. Oxford, Basil Blackwell, I962. . "The World Oil Outlook". Natural Resources and International Development, ed. Marion Clawson, Baltimore, Johns Hopkins, 1954. "Alberta MPR Data". Reservoir Engineering Digest, November 20, 19587 : Alberta. The Oil and Gas Conservation Board. Report  and Decision on Review of Plan for Proration of Oil to Market Demand in Alberta. Calgary, July, 1964.— . Oil and Gas Industry. Calgary, annual American Association of Petroleum Geologists;.Bulletin. Tulsa, Okla., monthly. American Petroleum Institute.Petroleum Facts and Figures. New York, biennial. Arps, J. J. "Valuation of Oil and Gas Reserves". Pet-roleum Production Handbook, ed. T. C. Frick, New York, McGraw Hi l l , I9b2, vol.2. Bank of Montreal. A Guide for Oil and. Gas Operators in Canada. Calgary, 1955. British Columbia. Department of Mines and Petroleum Resources, Petroleum and Natural Gas Branch. British  Columbia Monthly Crude Oil and Natural Gas Production. Victoria, annual. Ball, M. W. This Fascinating Oil Business. Indianapolis, New York, The Bobbs-Merril Co., 1940. Canada. Bureau of Statistics, Mineral Statistics Section. The Crude Petroleum and Natural Gas Industry. Ottawa, Queen's Printer, annual. Canada. The Royal Commission on Energy, Second Report. Ottawa, Queen's Printer, 1959. - 113 -Canadian Imperial Bank of Commerce, Petroleum and Natural Gas Dept. Principal Gas and Oil Fields in British  Columbia. Calgary, Sept., lybb. . Principal Oil Fields in Saskatchewan and  Manitoba. Calgary, September,1900. : . Principal Oil Fields in Alberta. Calgary, September, 190b. Canadian Oil and Gas Industries. Gardenvale, Que., National Business Publications, bimonthly (1948(?)-1963). Canadian Petroleum Association. Oil and Gas in Alberta. Calgary. . Statistical Year Book. Calgary, annual. Catawba Corporation. Petroleum Exploration in Canada  and the U.S.; A Comparative Study. New York, 19b3. Craze, R. C. and Glanville, J. W. Well Spacing. Houston, The Humble Oil and Refining Co., Sept., 1955. Davis, John. Oil and Canada - United States Relations. National Planning Association (U.S.A.) and Private Planning Association of Canada, 1959. . Natural Gas and Canada - United States  Relations'! National Planning Association (U.S.A.) and, Private Planning Association of Canada, 1959. The Financial Post, Survey of Oils.,. Toronto, Maclean-Hunter, annual. Fisher, F. M. Supply and Costs in the U. S. Petroleum  Industry. Baltimore, Johns Hopkins (for Resources for the Future, Inc.), 1964. Goodall, D. P. An Historical Sketch of Oil and. Gas  Conservation in Alberta, Calgary, The Oil and Gas Conservation Board, 1957. Hanson, E. J. Dynamic Decade. Toronto, McLelland and Stewart, 1958 Howland, Robert D. Canada's National Oil Policy. A paper presented, at the annual meeting of the Canadian Institute of Mining and Metallurgy, Quebec City, April 25-27, 1966. - 114 -James Richardson & Sons, (Research Dept.). Winter  Activities of the Canadian Oils. Winnipeg, November lybb. Kjellberg, S. 0. and Lounsbury, J. P. The Canadian  Petroleum Industry, Achievements ancTRrospects. Calgary, The Toronto-Dominion Bank, Oil and Gas Department 1964. Murray, A. S. "Recent Trends in Canadian Drilling Practices". Canadian Oil and Gas Industries, February 1954. The Oil and Gas Journal. Tulsa, Okla., Petroleum Publishing Co., weekly. Oilweek. Calgary, Myers' Oil News, weekly. Plotnick, A. R. Petroleum; Canadian Markets and United  States Foreign Trade Policy. Seattle, University of Washington Press, 19b4. Quirin, G. David. Economic Issues in the Regulation of  Oil and Gas. University of British Columbia, 19b3 (approx.), unpublished paper. . Economics of Oil and Gas Development in  Northern" Canada. Ottawa, Queen's Printer, 1962.-The Royal Bank of Canada, Oil and Gas Department. Industry  Statistics. Calgary, July 31, 1966 . Royalty Payments to the Crown. Calgary, February 15, 1963. Shell International Petroleum Company Limited. The  Petroleum Handbook. London, 1959. Saskatchewan, Department of Mineral Resources, Petroleum and Natural Gas Branch. Petroleum and Natural Gas  Statistical Year Book. Regina, Queen's Printer, annual. The Toronto-Dominion Bank, Oil and Gas Department. Petroleum and Natural Gas Map of Canada. Calgary, 1966. U.S. Department of the Interior. An Appraisal of the petroleum Industry in the United States. Washlngton, D. C., January, 1965. - 115 -APPENDIX I Disposition of Sub-Surface Rights in Western Canada Province or Area Disposition. Freehold (in-cluding C.P.R., H.B.C., etc.) Provincial Govt. Federal Govt. British Columbia — 99$ + mm Alberta 11$ 80$ 9$ Saskatchewan 70$1 Manitoba 15$ 2 Yukon and N.W. Territories - - 100$ Sources: (a) The Catawba Corporation. Petroleum Exploration in  Canada and the United States (b) The Royal Bank of Canada. Saskatchewan Regulations -Leases and Reservations. May 1, 19b7 (c) The Royal Bank of Canada. Manitoba Regulations -Leases and Reservations. April 1, 1963 1) The Sask. government holds ti t l e to approximately 70$ of the mineral rights in the surveyed area of the province. 2) The Manitoba government holds title to about 15$ of the oil and gas rights in areas of the province now subject to geological and geophysical exploration. APPENDIX II 1. 2. Growth of Canadian Oil Reserves - by Major Fields - to December, 1950 Estimated Original^*re-coverable Average Reserves (in Discovery Thickness Millions of A.P. I. Year Field Depth of Pay Zone Barrels) Gravity 1936 Turner Valley, Alta 7,500' 68« 36° - 59° 1947 Leduc, Alta. 5,300' 36' + 300 35 - 40 1948 Redwater, Alta 3,200' 101' 800 35 1949 Golden Spike,Alta. 5,650' 477" 300 36 - 39 Joarcam, Alta. 3,250' 7' 60 38 Stettler, Alta. 5,200' 35' + 45 28 - 30 Excelsior, Alta. 3,900' 86' 20 37 1950 Acheson, Alta. 5,100' 84' 100 33 - 40 Fenn - Big Valley, Alta. 5,300' 51' 250 22 - 33 Total Original Recoverable Reserves 1,950 Sources: Canadian Imperial Bank of Commerce, Principal Oil Fields in Alta., Sask., Man., & B.C., 1966 1. Does not include fields in the "heavy" crude category. 2. This appendix, then, covers development in the period before the institution of prorationing. 3. Reserve estimates as of September 1966 4. This figure,for Turner Valley only,represents approx. remaining reserves as of 1947 APPENDIX III Growth of Canadian Oil Reserves - by Major Fields - December 1950 to December 1966 Discovery Year Field Depth Average Thickness of Pay Zone Estimated Original re-coverable Reserves (in Millions of Barrels) A.P.I. Gravity 1951 Daly, Man. 2,550' 40* 18 32° Wizard Lake, Alta. 6,450 352 240 35 Glen Park, Alta. 6,300 124 17 37-38 New Norway, Alta. 4,700 59 10 32-41 Duhamel, Alta. 4,600 40-80 10 33-37 1952 Bonnie Glen, Alta. 7,000 195 400 41-42 Westerose, Alta 7,250 190 110 41 Sturgeon Lake, Alta. 8,850 61 22 36-38 West Drumheller,Alta. 5,550 60 28 35-42 Malmo, Alta 5,000 40 11 38-40 1953 Virden-Roselea,Man. 2,030 33 17 30 North Virden-Scallion Man. 2,010 41 27 35 Midale, Sask. 4,600 17 100 28-40 Colville-Smiley,Sask. 2,350 10 20 31-36 Sturgeon Lk.South, Alta. 8,500 84 145 37-38 Joffre, Alta. 5,000 12 & 39 50 41-42 Erskine, Alta. 5,400 29 19 22-28 APPENDIX I I I (Cont'd.) Discovery Year F i e l d Depth. Average Thickness of Pay Zone Estimated O r i g i n a l r e -coverable Reserves ( i n M i l l i o n s of B a r r e l s ) A.P.I. G r a v i t y 1954 A l l d a , Sask. 3,710' 26« 23 36-40 Nottingham,Sask. 3,530 26 66 30-40 Pembina, A l t a . 5,300 22 1,600 35-42 Garrington, A l t a . 6,600 4 30 39-43 1955 Carnouff, Sask. 4,250 6 22 33-40 Hastings, Sask. 3,920 23 30 34-41 Steelman, Sask. 4,640 14 215 33-41 Weyburn, Sask. 4,600 25 338 25-32 Harmattan-Elkton,Alta 9,100 50 58 36 Sundre, A l t a . 9,050 33 32 32-41 B e l l s h i l l Lake, A l t a . 3,000 33 20 26 Boundary Lake,B.C. 4,300 11 ? 35 1956 M i l l i g a n Creek,B.C. 3,750 22 ? 41 Alameda, Sask. 4,410 9 15 36-40 Queensdale,Sask. 3,870 25 19 34-40 Medicine R i v e r , A l t a . 7 , i oo 29 22 38 St. A l b e r t - B i g Lake A l t a . 4,700 151 18 33 Willesden Green,Alta 6,250 10 26 4l 1957 Dodsland, Sask. 2,200 8 29 36-37 Willmar, Sask. 4,100 20 18 34-38 Harmatten E a s t , A l t a 8,600 28 62 38 I n n i s f a l l , A l t a . 8,600 79 66 44 Kaybob,Alta. 9,800 69 111 43 APPENDIX III (Cont'd.) Estimated Discovery Year Field Depth Average Thickness of Pay Zone Original re-coverable Reserves (in Millions of Barrels) A.P.I. Gravity 1957(Cont 1 d)Swan Hills, Alta. Virginia Hills,Alta. 8,150 9,300 46 44 800 174 41 37-39 1958 Carson Creek North, Alta. Simonette, Alta. 8,700 11,550 51 74 115 50 41 45-48 1959 Judy Creek,Alta. Swan Hills So.Alta. Peejay, B.C. 8,750 8,400 3,900 67 46 13 490 400 42-43 41 39 1961 Workman, Sask. 4,050 20 15 32-37 1962 Snipe Lake, Alta. 8,550 32 77 37 1963 Lost Horse Hill,Sask. Utikuma Lake, Alta. 3,850 5,650 26 11 13 15 28-30 40 1964 Goose River,Alta. Mitsue, Alta. 9,200 5,750 35 13 23 135 40 42-43 APPENDIX III (Cont'd) Discovery Year Field Depth Average Thickness of Pay Zone Estimated Original re-coverable Reserves (in Millions of Barrels) A.P.I. Gravity 1965 Nipisi, Alta. Weasel, B.C. Rainbow Lake, Alta. Zama Lake, Alta. Bistcho Lake, Alta. 5,650 3,800 18 18 600+ 100 1 5001* '4002« ? 41-42 40 Source: Canadian Imperial Bank of Commerce, Principal Oil Fields in Alta., Sask., Man., & B.C., 1966 — — — — _ 1. Recent estimate, April 1967, by Richardson Securities of Canada 2. Recent estimate, April 1967, by Richardson Securities of Canada - 121 -APPENDIX IV The Alberta Maximum Permissive Rate (MPR) Formula The MPR is an estimate of the maximum efficient rate (MER) at which a pool should be produced having regard for reservoir characteristics and conservation principles. When a pool MER, based upon an analysis of the pool recovery mechanism, is not set by the Board (as in fact i t seldom seems to be), the pool MPR is determined as the ultimate recoverable reserves of the pool divided by the number of days in the estimated " l i f e " of the pool. This l i f e in turn is estimated having regard to well spacing, rate of pressure decline, permeability, viscosity and pay thickness. Present practice sets the l i f e as approximately 10 years for a l l pools on 40 acre spacing, and for pools of very favorable characteristics regardless of spacing. For pools developed on wider spacing,or having character-istics less favorable than the usual, the li f e is extended to a degree dependent upon the spacing and the character-istics. The range of "lives" employed in the "Board's" MPR formula is from about 8 years to some 40 years. The MPR formula itself is as follows: 1 1 MPR (per well) = N40 X R X S X L40X?65 x F where N40 oil in place per 40 acres R percentage of o i l in place which is considered recoverable. S actual well spacing (in acres) 40 acres - 122 -L40 x 365 = l i f e of the pool (in days) on 40 acre spacing P = the l i f e factor modifier which relates the l i f e of the pool on the actual spacing to the li f e on 40 acre spacing. Note that the first three terms of the formula, namely N40, PI, and S, yield an ultimate reserves figure per well. These reserves, of course, are commonly expressed in barrels. 1 1 The factors , , - and are then applied L40 x 3t>5 p to this reserves figure to give the rate at which they may be produced. These last two expressions are in per day units hence giving the MPR in barrels per day. (Note that allocation among o i l pools on the basis of MPR's then is in fact an ultimate reserves system modified by a li f e factor which in turn is dependent upon spacing, pressure decline, permeability, etc.) As mentioned the physical characteristics of most pools were such that they were given a "uniform rate l i f e " of approximately 10 years i f drilled on 40 acre spacing. Wider spacing would (unless the pool was one exhibiting extremely favorable characteristics) bring the l i f e factor modifier term (^)into play causing the "uniform rate l i f e " to be extended - i.e. lowering the pool MPR. It is evident then that the MPR formula led to progressive reduction in production allowables per acre as pools were developed on greater than 40 acre spacing. And as allocation of the provincial "demand" among pools was - 123 -based on MPR this had the effect that a pool d r i l l e d on wide spacing would receive a lesser share than i t would i f i t had been d r i l l e d at 40 acres. It perhaps should be emphasized that just because we assume MPR's would be maintained by the various provincial regulatory bodies that we are not therefore implying that the MPR rate of pro-duction is the best rate of production in an economic sense. The MPR rate of production, as we have mentioned, is that rate which w i l l allow the quickest depletion of a reservoir without sacrifice of any of the potential output of the reservoir - i.e. this rate seeks to ensure that ultimate recovery from the reservoir w i l l be maximized. The economic best rate of production on the other hand would be that rate which over the long term would maximize benefits relative to costs of o i l production. If equality existed between private and social benefits, and i f there was equality between social and private rates of time discounting then the economic best rate of production over time to society would be that rate which (and assuming competition between producers), maximized benefits over costs to the producer. Three factors of primary importance must be known to make possible the determination of the economic rate of production: (i) producers' future costs of developing reserves ( i i ) future demand for crude ( i i i ) future discount rates - ]23A -Because i t is in fact not possible to correctly forecast these variables the economic best rate of production at any point in time cannot be calculated - for i t to be calculable perfect knowledge would be required. Even i f i t were determinable however i t is clear that such a rate of production would only by coincidence be the same as the usually arbitrarily chosen MPR rate of production. Notwithstanding our ina b i l i t y to determine the economic rate there are some things that can be said about how the economic and MPR rates would compare given certain assumptions: (i) If reserves could always be replaced with reserves of equal cost, i f demand levels were unchanging, and i f the rate of discount was zero then the economic best rate would not exceed MPR. It might be equal to or less than MPR but i t would not be greater. ( i i ) If demand in future was to increase the economic best rate would tend to a rate slower than MPR; conversely i f future demand was to decrease i t would tend to a rate greater than MPR. ( i i i ) If future demand remained at constant levels but the discount rate was positive the. economic rate would tend to a rate faster than MPR. (iv) If the cost of developing future reserves was greater than the cost those presently being produced the economic rate would tend to a rate which would not exceed MPR. - 123B -We can be f a i r l y certain that the rate of discount w i l l always be positive which would suggest economic rates of production greater than MPR's. However future demands and costs of production, i f :they were known, might point either to economic rates of production faster or slower than MPR's. What then i s the rate to be? In North America at least, society, through i t s regulatory boards has decreed that MPR i s in fact the 'best' guess of the rate, feeling that the most lik e l y future trends are that costs of future reserves w i l l be higher than those presently being produced, and that demand w i l l be higher. APPENDIX V Excess I n f i l l Wells D r i l l e d i n Western Canada"*" From January 1947 t o December 1965 a) Excess I n f i l l Wells i n A l b e r t a Required Spacing 2 No. of No. of of w e l l s Wells at Excess F i e l d W e l l s 2 (acres) "Best" Wells Remarks Spacing^ Acheson & Acheson E. 132 40 33 99 A e r i a l 10 40 3 7 Alderson East 6 160 6 -A l i x 13 40 3 10 A l l i a n c e 5 40 1 4 Ante Creek 15 320 15 -Arm!sie 7 40 2 5 Alhambra 12 160 12 -Barons 7 40 2 5 Bashaw 38 120 approx 28 10 B a t t l e 13 40 3 10 B a t t l e South 14 40 4 10 B a t t l e North 4 40 1 3 B e l l s h i l l Lake 91 40 40 160 23 68 Bonnie Glen 157 at 1 6 §S 55 118 B u f f a l o Lake 4 2 2 Bentley 56 80 28 28 B i g Lake 16 40 4 12 Campbell - Namao 32 40 8 24 Car o l i n e 8 160 8 -Carrot Creek 7 160 7 -Carson Creek 56 320 56 -Chamberlain 3 40 1 2 Sub T o t a l 722 305 417 Required No. of Spacing Wells at No. of of well s" "Best" Exces . Field Wells (acres ) Spacing; Wells Fwd. 722 305 417 Chigwell 6 160 6 _ Choice 9 40 2 7 Clive 70 40 18 52 Conrad 15 40 4 11 Crossfield 140 160 & 320 140 -Cyn-Pem. 22 160 22 -Del Bonita 12 40 3 9 Drumheller 23 40 6 17 Duhamel 28 40 7 21 Eaglesham 5 80 3 2 Ed son 24 160 24 -Ellerslie 6 • 40 2 4 Erskine 96 40 24 72 Ethel 4 320 4 -Ewing Lake 28 80 14 14 Excelsior 34 40 9 25 Fairydell 37 40 10 27 Fenn - Big Valley 337 40 85 252 Fenn West 30 80 15 15 Ferrier 16 160 16 -Freeman 11 160 11 -Garrington 103 320 103 -Gilby 159 80 80 79 Giroux Lake 7 160 7 -Glen Park 16 40 4 12 Golden Spike 27 80 approx 13 14 Goose River 27 320 27 -Hamilton Lake 62 6o approx 23 39 Sub Total 2,076 987 l,0b9 Spacing No. of of wells Field Wells (acres) Fwd. 2,076 . Harmatten Elkton 76 8.0 Harmatten East 96 80 Homeglen - Rimbey 38 160 Horsefly Lake 16 40 Hussar 60 40 Hutton 12 40 Innisfail 90 80 Joarcam 474 40 Joffre 411 80 a Joffre South 7 40 Judy Creek 232 160 Judy Creek South 5 320 Jumping Pound 12 640 Kaybob 101 160 Kaybob South 91 160 Lanaway 10 320 Leafland 58 160 Leafland North 14 160 Leduc - Woodbend 1,278 40 Legal 7 40 Little Smoky 3 80 Lochend 6 160 Lousana 2 160 Sub Total 5,175 Required No. of Wells at "Best" Spacing 9 8 7 3 8 4 8 19 4 15 3 23 119 rox 206 2 116 5 12 50 91 10 58 14 320 2 2 6 2 Excess Wells 1,089 38 48 19 12 45 9 67 355 205 5 116 51 958 5 1 Remarks Only 15 wells be-ing produced. 320 acre spacing O.K. 320 acre spacing O.K. Only 7 wells producing 320 O.K. Only 66 wells being used 320 O.K. Only 40 wells being used 2, 152 3,023 Required No. of Spacing Wells J No. of of wells "Best" Field Wells (acres) Spacin, Fwd. 5,175 2,152 Malmo 51 40 13 Medfcine River 166 80 83 Mitsue 191 160 96 Morinville 16 40 4 New Norway 17 40 5 Nipisi 90 160 90 Normandville 11 80 6 Peavey 12 4o „ 3 Pembina 3,221 140 approx2«20 ave Provost 7 40 2 Princess 17 20 5 Red Coulee 17 40 5 Red Earth 23 80 12 Redwater 926 40 232 R©cky Mtn.House 11 80 6 Rose Bud 5 40 2 Rowley 12 160 12 St. Albert - Big Lake 22 40 6 Samson 3 40 1 Simonette 22 160 11 Ska.ro 4 40 1 Sub Total 10,019 5,567 Excess Wells Remarks 3,023 38 83 95 Say 320 O.K. high gravity 12 12 5 401 5 12 Low gravity say 80 acre/well 12 11 694 5 3 16 2 11 320 acre O.K. very high gravity 4,452. No. of Field Wells Fwd. 10,019 Snipe Lake 96 Spring Coulee 4 Stettler 133 Stettler South 11 Sturgeon Lake 20 Sturgeon Lake South 152 Sundre 58 Sunset 5 Swan Hills 699 Swan Hills South 21? Sylvan Lake 76 Thompson Lake 17 Three Hills 5 Twining 24 Twining No. 21 Utikuma Lake 22 Virginia Hills 104 Wayne Rosedale 12 West Drumheller 80 Westerose 19 Westward Ho 42 Whitemud 4 Willesden Green 270 Wimburne 24 Sub Total 12,134 Required No. of Spacing Wells at of wells "Best" Excess (acres) Spacing Wells Remarks 5,567 4,452 160 48 48 320 acre spacing O.K. Only 43 wells operating 40 1 3 60 approx 50 83 40 3 8 80 , 10 10 80 76 76 80 29 29 160 5 160 350 349 320 acre O.K. High gravity 160 108 109 320 acre O.K. only 60 wells producing 160 76 40 5 12 160 5 160 24 160 21 160 22 160 52 52 320 acre spacing O.K. 40 3 9 40 20 60 80 10 9 80 21 21 40 1 3 160 270 120 approx 18 6 Very prolific high gravity 6,795 5,339 Field Fwd. Wintering Hills Wizard Lake Wood River Yekau Lake Youngstown No. of Wells 12,134 8 64 5 12 5 Spacing of wells (acres) 160 40 160 40 40 Low Gravity & other 1,543 Required No. of Wells at "Best" Spacing 6,795 8 16 5 3 2 1,543 Excess Wells 5,339 48 9 3 Remarks Totals - Alberta 13,771 8,372 5,399 1. Fields in the heavy category (with oil gravity of 24 API or less) are not included. Close spacing in these fields may well be justified. Turner Valley also is not included as being before the time of our main concern. 2) The Financial Post.Survey of Oils, 1966. Alberta, O.G.C.B., Oil and Gas  Industry, Annual Reports. 3) "Best" spacing is assumed to be 160 acres unless specified otherwise. b) Excess I n f i l l Wells In Saskatchewan Field Alameda Alida Areola Benson Bone Greek Browning Carnduff Clarilaw Coleville - Smiley Dodsland East Northgate Elmore Flat Lake Freestone Gainsborough Glen Ewen Griffin Handsworth Hastings Huntoon Kenosee Lake Alma Lightning Lost Horse H i l l Sub total Spacing No. of of wells Wells2*. (acres)4 110 80 76 80 18 80 65 80 30 80 15 80 216 80 5 80 272 40 399 80 4 80 33 80 17 160 12 80 7 80 49 160 3 80 16 80 171 80 31 160 8 80 4 160 10 80 34 80 ,605 Required No. of Wells at "Best" Excess Spacing5 Wells Remarks 55 55 38 38 9 9 33 32 30 - 80 acre spacing O.K. Gravity of o i l low at 26° API 7 8 108 108 3 2 Q 68 204 Low gravity (l4 API) formation of this fie not included 200 199 2 2 17 16 17 6 6 4 3 49 2 1 8 8 86 85 31 4 4 4 5 5 17 17 803 862 Spacing No. of of wells Field Wells (acres) Fwd. 1 , 6 0 5 Lougheed 19 8 0 Melrose 5 8 0 Midale 404 8 0 Northgate 21 1 6 0 Nottingham 172 8 0 Oungre 2 5 1 6 0 Parkman 1 2 8 8 0 Pinto 127 1 2 5 Queensdale 9 4 8 0 Rocanvilie 9 8 0 Sherwood 1 6 8 0 Star Valley 23 8 0 Steelman 6 9 5 8 0 Stoughton 1 2 8 0 Wapella 27 4 0 West Kingsford 2 5 8 0 Weyburn 5 8 5 8 0 Whiteside 3 4 8 0 Willmar 8 6 8 0 Workman 1 3 0 8 0 Other light & med. areas 3 3 8 0 Low gravity wells and others 1 , 9 2 0  Totals - flask, 6 , 1 9 5 Required No. of Wells at "Best" Excess Spacing Wells Remarks 803 802 10 9 2 3 202 202 21 86 86 2 5 64 64 100 27 Some wells at 80 acres and some at 1 6 0 . Ave= 125 acres. 47 47 5 4 8 8 12 11 348 347 6 6 ' O r , 14 13 Oil gravity 25 -27 API 1 2 1 3 2 9 3 2 9 2 1 7 1 7 4 3 4 3 6 5 6 5 1 7 1 6 1 , 9 2 0 assume opt. spacing 8 0 acres. 4 , 1 2 0 2 , 0 7 5 4) The Financial Post.Survey of Oils, 1966. The Canadian Imperial Bank of Commerce. Principal Oil Fields in Saskatchewan and  Manitoba, Sept. 1966"; ' : 5) "Best" spacing is assumed to be 160 acres unless otherwise specified. c) Excess I n f i l l Wells in Manitoba Required Spacing No. of No. of of wells Wells at Excess Field Wells6 (acres)° 160 acres Wells Daly 167 40 42 125 Ebor 13 40 4 9 Kirkella 9 40 3 6 Maples 9 40 3 6 North Virden -Scallion 231 40 58 173 Routledge 70 40 18 52 Virden - Roselea 287 40 72 215 West Routledge 49 40 13 36 Other 62 40 16 46 . Totals - Manitoba 897 229 668 Remarks 6) The Financial Post-Survey of Oils. 1966. The Canadian Imperial Bank of Commerce, Principal Oil Fields in Saskatchewan and  Manitoba, September 1966. 133 -APPENDIX VI Average Depth of the Excess Development Wells The average depth of excess development wells is arrived at below by consideration of wells in those fields where most of the excess i n f i l l drilling has taken place. Field Alberta Acheson & Acheson East Bonnie Glen Fenn - Big Valley Joarcam Joffre Judy Creek Leduc Woodbend Mitsue Pembina Redwater Swan Hills Swan Hills South Sub Total (Alta.) Saskatchewan Carnduff Colville-Smiley Dodsland Midale Steelman Weyburn Sub Total (Sask.) Manitoba No. of Excess Depth of Wells 1 Wells (ft.) 99 118 252 346 196 116 945 95 401 676 349 109 3,702 108 204 199 202 347 292 1,352 Daly 125 North Virden - Scallion 173 Virden Roselea 215 Sub Total (Manitoba) 513 Totals 5,567 5,100 7,000 5,300 3,250 6,500(ave) 8,750 5,300 5,750 5,300 3,200 8,150 8,400 Total Footage (ft.) 505,000 827,000 1,335,000 1,125,000 1,100,000 1,015,000 5,000,000 545,000 2,125,000 2,160,000 2,845,000 915,000 4,250 2,350 2,200 4,600 4,640 4,600 2,550 2,010 2,030 19,497,000 460,000 480,000 440,000 930,000 1,610,000 1,340,000 5,260,000 320,000 350,000 435,000 1,105,000 25,682,000 - 134 -Average Well Depth = 25,682,000 = 4,650' (approx.) 5,5b7 See Appendix V - 135 -APPENDIX VII  Productive Oil Development Wells -Drilled in Western Canada 1947 - 1965 Year No. of Wells 1947 209 1 194a1 260 1949 521 1950 775 1951 660 1952 1,065 p 1953 1,077 1954 1,128 1955 1,809 1956 2,146 1957 1,674 1958 1,335 1959 1,257 I960 1,379 1961 1,255 1962 1,152 1963 1,294 1964 1,448 1965 1,483 Total 21,923 1. Figures for 1947'to 1952 inclusive are from the June issues of the "Bulletin of the American Association of Petroleum Geologists". Figures for 1947 are given in the June 1948 issue, and so on. 2.. Figures for 1953 to 1965 inclusive are from the CP.A. Statistical Year Books, years 1958 to 1965. APPENDIX VIII Actual Crude Oil Production - Western Canada Light and Medium Categories Total Production (Bbls. x 1000) Year 1965 1964 1963 1962 1961 I960 1959 1958 1957 1956 1955 1954 1953 1952 1951 1950 1949 1948 1947 Alberta 188,298 175,442 168,214 165,125 157,812 132,865 129,967 113,278 137,492 143,910 113,035 87,637 76,816 58,919 45,915 Sask. 87,775 81,384 71,307 64,432 55,859 51,868 47,443 44,626 36,861 21,067 11,317 5,422 2,791 Man. 4,947 4,417 3,771 3,928 4,480 4,764 5,056 5,829 6,089 5,786 4,145 2,148 656 B.C. 13,470 11,525 12,515 8,917 1,016 867 866 512 Heavy Crude Prod. W. Canada (Bbls. x 1000) 31,212 29,858 23,144 19,481 17,092 16,882 17,356 15,942 15,453 14,082 10,016 5,985 4,003 1,706 1,518 Total Prod. Lt. & Med. Categories (Bbls. x 1000) 263,278 242,910 232,663 222,921 202,075 173,482 165,976 148,303 164,989 156,681 118,481 89,222 76,260 57,213 44,397, 29,064i 18,786 9,594 5,822 1 Source: The Financial Post, Survey of Oils 1966, pp.21-32 The Financial Post, Survey of Oils 1950 The Financial Post, Survey of Oils 1952 1) Alberta. O.G.C.B. Oil and Gas Industry, 1947 to 1950. All production in l t . and med. category 1947 to 1950 from Alberta. F i e l d 1965 1964 1963 1962 1961 i960 1959 1958 Bantry 1,421 967 376 271 230 16 18 10 Bigoray 198 181 186 150 125 89 6 _ Chauvin 188 156 131 100 141 140 148 151 Glenevis 357 255: 250 222 79 30 84 43 Lloydminster 532 609 450 305 497 574 642 646 Taber 756 470 202 89 50 94 77 129 Wainright 1,254 714 .176 553 605 749 982 1,141 Others- 1,500 1,500 500 1,500 1,500 1,000 1,000 1,000 T o t a l 6,206 4,852 3,271 2,190 3,227 3,192 2,957 3,120 F i e l d 1957 1956 1955 1954 1953 1952 1951 Chauvin 152 182 179 162 98 Glenevis 142 57 39 35 Lloydminster 895 1,092 1,222 1,101 1,059 1,057 900 Taber 139 121 111 114 66 81 182 Wainright 997 679 208 124 69 28 14 Baxter Lake 24 24 34 34 45 20 2 B o n n y v i l i e 10 27 37 42 45 20 . 10 Hughenden 35 Other* 800 800 800,. 500 500 500 400 T o t a l 3,194 2,982 . 2,630 2,112 1,882 1,706 1,518 Source: The F i n a n c i a l Post, Survey of O i l s , 1966, 1959, 1952 1. Q u a n t i t i e s shown here are about one-half of the production amount shown under the F i n a n c i a l Post heading "Misc. F i e l d s " . Heavy Crude Production - Saskatchewan (Bbls. x 1000) Field 1965 1964 1963 1962 1961 i960 1959 Aberfeldy 454 237 84 5 Battrum 2,880 1,3H 1,035 789 856 955 Cantuar ^ 897 879 910 898 880 999 Colville - Smiley 875 1,000 1,000 1,000 1,000 1,200 Do Hard 4,772 4,740 . 4,581 4,030 4,034 4,096 Delta 27 Fosterton 4,203 3,207 2,754 1,987 1,951 2,04l Gull Lake 831 926 829 536 533 545 Hazlet 127 Instow 3,270 2,776 2,365 1,843 1,787 1,618 Leitcville 89 122 96 33 Leon Lake 76 54 4 9 22 Lloydminster .512 459 347 460 531 651 Lone Rock 732 494 471 408 441 479 North Premier 270 171 159 158 146 136 Rapadan 998 880 733 217 46 73 Success 3,069 2,095 1,798 1,422 1,401 1,434 Other 1,000 500 75 75 75 150 Total 25,006* 25,006 19,873 17,291 13,865 13,690 14,399 Source: The Financial Post, Survey of Oils 1966 1. Approximately one-half of field production assumed heavy gravity. 2. Estimate Heavy Crude Production - Saskatchewan (Bbls. x 1000) !  Field 1958 1957 1956 1955 1954 1953 Battrum 895 932 843 21 Cantuar 1,184 1,347 1,357 640 101 19 Colville - Smiley 1,000 1,500 1,500 1,500 1,000 350 Do Hard 3,122 2,079 1,302 323 217 25 Fosterton 2,043 1,907 1,867 1,353 212 68 Gull Lake 472 455 532 547 328 71 Instow 1,046 640 218 . Leon Lake 32 32 844 Lloydminster 658 798 883 946 892 Lone Rock 383 502 635 728 696 548 McLaren 69 98 39 47 North Premier 152 167. 90 Rapadan 100 94 338 124 Success 1,585 1,656 1,729 1,155 Other 150 150 75 75 50 25 Total 12,822 12,259 11,100 7,386 3,873 2,121 Source: The Financial Post, Survey of Oils 1959 Actual Crude Oil Production - Western Canada (1947-1950) Light and. Medium Categories ' (Bbls.) Field. 1950 1949 1948 1947 Turner Valley Leduc Redwater Golden Spike Joarcam Stettler Excelsior Fenn - Big Valley Acheson Total 3,344,000 10,589,000 10,746,000 293,000 169,000 246,000 272,000 10,000 51,000 29,064,000 4,304,000 9,689,000 4,793,000 18,786,000 4,900,000 4,657,371 36,875 9,594,000 5,450,000 372,000 5,822,000 Source: Alberta Oil & Gas Conservation Board, Oil & Gas Industry, Annual Reports 1947 to 1950. - 141 -APPENDIX IX  Industry Rate of Return "Exploration expenditures" from 1947 to 1965 have amounted to approximately $4 billion (Footnote #10, p.105) made up nearly equally of about $2 billion for what we may call "real" exploration expenditures on such things as geological and geophysical exploration, exploratory d r i l l -ing, and overheads, and of about $2 billion for economic rents in the form of payments for land acquisitions and land rentals. Implicit in the statement that the amount of exploration (by which we mean the "real" exploration of some $2 billion) undertaken under the model developed in Chapter III would be the same, is the assumption that under such a scheme, and at the lower possible price of crude, industry profitability - i.e. rate of return on invested capital - would have been the same as i t in fact has been. Our contention is that rate of return to total invested capital in the industry is the most important determinant of exploratory activity and that i f this rate of return is the same under the model as i t in fact has been that i t is reasonable to assume the amount of exploration would be the same also. To investigate whether or not i t is reasonable to think that the total industry rate of return under the model could be the same consider Figs. A and B below. Fig A represents the current situation with curve XZ being the supply curve of firms in the industry today. We assume - 142 -for simplicity that each operating field produces an equi-proportionate amount of the total output and that supply costs increase in the linear manner shown. Ptuce. b loo Zoo ioo 4oo SOD D loo loo ioo Aoo 5oo ltJ.ooi-rG.~f Oorfiar (coo's) i/Joosre.-^ OOTPOT (OOO'S.) Fig. A Fig. B With the price of crude at $2.75 - and again simplifying hy assuming that a l l producers receive this price - industry profits under such a scheme, i f industry output was 500,000 b/d, would be represented by the triangle XYZ and would ,, 500,000 b/d amount to $187,500 / day ($0.75 x g ) (Though we use an industry output figure of 500,000 b/d this is just for expository purposes. Any figure which we might have chosen will leave the argument unaffected). This sum could be calculated to represent some specific rate of return on invested capital. We postulate that this rate of return, whatever i t is, is the rate necessary to have brought about that amount of exploration which has actually taken place -and further that this amount of exploration has been the required amount to maintain the long term price - 143 -of crude o i l in the $2.75 range, where i t in fact has been for many years, Fig. B represents fields operating as under the model of Chapter III. We postulated earlier - pp. 94 & 95 - that costs of producing from the low cost fields (but s t i l l at half capacity) would run from $ 1 . 8 l / bbl. to $2.15 / bbl. and that operating at f u l l capacity would result in capital costs being reduced by llc£ / bbl. and operating costs by 9^ / bbl. The supply curve then, we suggest, for the low cost fields operating at f u l l capacity would run from $ 1 . 6 l / bbl. to $1.95 / bbl. (RS in Fig. B). Again we assume each field produces an equi-proportionate amount of the total output and that field costs increase linearly as shown. Capital investment under the Chapter III model would have been approximately $1,230 million less than i t has been ($555 million ( p . 6 l ) , plus about $675 million (pp.80,8l))or 18.5$ less. Industry profit then could have been 18.5$ lower and s t i l l maintained the same rate of return - i.e. profit could have been $34,500 / day less than the $187,500 / day cal-culated above or $153,000 / day. We see from Fig B however that profit is only $85,000 / day (triangle RST), or $68,000 less than that necessary to have kept exploration at the observed level - the level, we say which would have been necessary to produce the output of crude which has taken place i f the price level had been $1.95 / bbl. To achieve the same rate of return industry revenue would have to have been nearly l4c/ / bbl. more ($68,000 / day). - 144 -For this to be achieved either the price of crude would have to have been 14(/ / bbl. higher than $1.95 or economic rents paid by industry to landowners would have to have been on average l4$£ / bbl. less. We suggest that i t is reasonable to think that this latter course would have taken place. The total amount of money paid out in the form of land acquisitions and rentals from 1947 to 1965 we have said has been about $2 billion; the amount of o i l produced in this time was about $2.7 billion bbls. If the l4ci / bbl. amount necessary to keep exploration at the same level had been shifted to the landowners i t would have meant a total amount over this period of $380 million (l4t/ / bbl. x 2.7 billion bbls.). It is certainly reason-able to think that this proportion of $2 billion could have been shifted and therefore that at a price of $1.95 per bbl. the same industry rate of return could have been maintained. 

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