The Royal Society of Canada La Societe Royale Du Canada Energy Resources

THE ROYAL SOCIETY OF CANADA LA SOCIETE ROYALE DU CANADA

ENERGY RESOURCES

October 15-16-17 octobre 1973

Sixth Symposium THE ROYAL SOCIETY OF CANADA LA SOCIETE ROYALE DU CANADA

SYMPOSIUM ON ENERGY RESOURCES

October 15-17, 1973

Organizing Committee G.C. Laurence, F.R.S.C. Chairman K.J. Laidler, F.R.S.C. Editor R.J. Uffen, F.R.S.C. J.H. Dales, F.R.S.C. A.D. Scott, F.R.S.C. M.C. Urquhart, F.R.S.C. Copies may be obtained from: The Royal Society of Canada 395 Wellington Street Ottawa, Ontario, K1A 0N4 Price: $7.00 (Postage included) The Royal Society of Canada

Guy Sylvestre

President, 1973-74 TABLE OF CONTENTS Page Acknowledgements vi Editor's Foreword vi i SESSION I: ENERGY RESOURCES AND THEIR DEPENDENCE ON PRICE D.J. McLaren, F.R.S.C., Chairman tf.C. McCrossan The origin and geological environ- 3 ment of the mineral energy resources O.K. Mclvor & Potential oil resources and their 17 dependence on price and government share D.D. Lougheed Energy resources and their 45 dependence on price: natural gas V.L. Horte Alberta's oil sands in the energy 55 supply picture (presented by 6.W. Govier G.A. Warne) G.D. Coates Relationship between coal price 71 levels and quantity of economically recoverable coal in Canada • R.E. Folinsbee, F.R.S.C Uranium and thorium: future energy 81 & A.P. Leech sources Discussion of Session I 99 SESSION II ENERGY MARKETS AND THEIR DEPENDENCE ON PRICE R6al Boucher, Chairman J.H. Dagher The longer term outlook for oil 115 R.R. Colpitts Energy markets and their dependence 133 on price: gas markets M.D. Lester & Large industrial users and the 149 J.T. Madill energy market D.C. Downing Hydrocarbons for petrochemicals 157 W..S. Wilson Energy and Canada's transportation 163 industry J. Pill Energy markets and urban development 171 Discussion of Session II 179 "IV

SESSION III: PROSPECTS OF TECHNOLOGICAL CHANGE W.B. Lewis, F.R.S.C., Chainr.an Page W.B. Lewis, F.R.S.C. The nuclear energy industrial 189 complex and synthetic fuels \/ P.J. Mooradian, F.R.S.C. Fission, fusion and fuel economy 195 G.D. Garland, F.R.S.C. Geothermal energy: an undeveloped 217 Canadian resource? B.E. Conway, F.R.S.C. & Energy conversion: fuel cells and 235 A.K. Vijh electrolysis L. Boulet Electrical energy transmission 249 M.D. Armstrong & Prospects for urban transit 261 J.H. Morgan systems Discussion of Session III 269

SESSION IV: APPLICATIONS OF ECONOMICS TO QUESTIONS INVOLVING ENERGY A.D. Scott, F.R.S.C. , Chairman A.D. Scott, F.R.S.C. Economists and energy problems 275 J.E. Gander Canada and the world energy 279 situation J. Helliwell Estimating the national economic 291 effects of arctic energy development G.D. Quirin Energy: policy choices regarding 307 exploitation and export J.H. Dales* F.R.S.C. Rising energy prices and economic 331 structure Discussion of Session IV 337 SESSION• V: ENVIRONMENTAL CONSIDERATIONS

F.K. Hare, F.R.S.C., Chairman Page E.F. Roots Energy and the environment •• a 349 perspecti ve /O.G. Hurst, F.R.S.C. The safety of nuclear technology 357 A?&tS?8 G.C. Butler, F.R.S.C Health hazards from nuclear 377 sources E.B. Peterson The pipeline problem in review 389 I.E. Efford Energy: profits from reducing 401 demand A. Biswas Summing up 413 Discussion of Session V 419

SESSION VI; HUMANISTIC AND SOCIAL CONSIDERATIONS R.J. Uffen, F.R.S.C., Chairman O.E. Th'ur Energy resources - manpower 429 considerations J.J. Deutsch, F.R.S.C. The effects of energy on life 437 styles Mrs. W.A. Brechin Energy in the home - the consumer, 443 participant or pawn? K.J. Duncan Problems: of native peoples 453 Donald MacDonald Energy: boon or bane? 459 Discussion of Session VI 463

EPILOGUE G.C. Laurence, F.R.S;C. On planning for sale and use of 467 energy Glossary 473 List of Speakers and Organizers 481 List of Registrants 485 Proceedings of Symposia 500 Royal Society of" Canada Symposia 501 vi

ACKNOWLEDGEMENTS

The Royal Society of Canada is gratefully appreciative of the very valuable contributions to the proceedings of the symposium by the chairmen of the sessions, invited speakers and others who participated in discussion, and of the encouragement it received from the Department of Energy, Mines and Resources. In planning and organizing the symposium I was encouraged and helped by many whom I consulted. I am particularly grateful to Dr. K.J. Laidler for performing the large task of collecting a record of discussion and the papers and getting this volume published, and to Mr. E.H.p. Garneau for his careful attention to organization details. The success of the sessions is due mainly to the time-consuming efforts of their chairmen: Dr. D.J. McLaren, M. RSal Boucher, Dr. W.3. Lewis, Dr. A.D. Scott, Dr. P.K. Hare and Dr. R,J. Uffen.

G.C. Laurence Chairman

November, 1973. VI 1

EDITOR'S FOREWORL

At the meeting, the presentation cf a group of papers was followed by a discussion, which was usually at the enri of each session. A tape recording of the discussions was not made. Experience with previous symposia showed that even if a recording is made, speakers usually wish to rewrite their contributions. The record of the discussions that is found in the present publication is based entirely on written submissions, and includes accounts of what was said at the meeting and additional questions and comments that were not brought forward at the meeting. I have not tried to distinguish between these (since there was considerable overlap) but have merely arranged the material in what seems to be a logical order. I have tried to obtain answers to all of the questions that were put to the speakers, and in most cases was successful.

Prior to publication, the discussion sections were sent to all questioners and respondents, who have had the opportunity to make any changes or additions. In the end I believe that everyone has had full opportunity to present his point of view.

My task as Editor has been very considerably lightened by the help I have received from itiany persons, in particular the following: Dr, G.C. Laurence, the Symposium Chairman; Major E.H.P. Garneau, our Executive Secretary, and his staff for constant support and assistance; Miss Judy Yaworsky, of "The Agency," who did not confine her activities to public relations but helped in many other ways; Dr. Anthony Scott and Dr. Arsit Biswas, for help with the editing of discussion sections; Mrs. Carol Fauteux, for excellent secretarial work; and Mrs. Alice Leech for her very careful proofreading.

K.J. Laidler November, 1973. SESSION I

ENERGY RESOURCES AND THEIR DEPENDENCE ON PRICE

Monday, 15 Octobers 1973, a.m.

Chairman D.J. MCLAREN, F.R.S.C. Director, Geological Survey of Canada f\»

Figure 1 - upper Devonian Paleogeography (after Nelson. S.J., 1970) THE ORIGIN AND GEOLOGICAL ENVIRONMENT OF THE MINERAL ENERGY RESOURCES by R.G. McCROSSAN Institute of Sedimentary and Petroleum Geology, Calgary INTRODUCTION I have been asked to provide some background for the benefit of non-geologists on the way in which the energy mineral resources occur in nature. The mineral energy resources have at least two things in common with minor exceptions. They occur in sedimentary rocks, and all the economically exploitable concentrations of these materials are very unevenly distributed in the earth's cru«;t, as Premier Lougheed would be quick to point out. Oil, gas and coal have a number of other geological characteristics in common. I am going to talk about three types of commodities: petroleum (or oil and gas); coal; and uranium. Since economic deposits of all of these occur in sedimentary rocks, I would like by way of background to discuss the nature of sedimentary basins and their formation. SEDIMENTARY BASINS The earth's crust, as I am sure that you are all aware, is a dynamic thing in a constant state of motion with large and complex stress fields within it. At any instant of time the motions are not generally obvious except in the case of major earthquakes, but cumulated over geologic time the results of this activity are very large indeed. It is generally accepted by geologists today that large slabs of the earth's crust have moved horizontally over great distances with respect to one another. As a result the lighter partsof the crustal material or the continental masses have drifted apart leaving the ocean basins between them, or pushed against each other creating Targe compressional features near the interfaces in the form of major upwarps and downwarps. In other areas under tension as a result of lack of support, from beneath caused perhaps by such things as density changes in the mantle, and/or the pull-apart, collapse may occur. Thus there is on the continents and their bordering areas a surface of great relief which the forces of atmospheric weathering and gravity continually attempt to smooth by eroding rock' material off the high surfaces and depositing it in the bordering depositional basins. As well as horizontal movements of these major elements of the earth's crust, there seems to have been at various periods in the geologic past large vertical movements which have caused marine waters to invade or withdraw from large areas of the continent. Basins are filled with sediment brought in from the surrounding highlands by rivers in form of muds and sands. In addition large quantities of sediment are generated within the basins in the form of TOTAL BASIN FILL

Unmetemorphofcd Sedimentary Rocki

Figurt 2 - Total thickness uiMetamorphosed sedimentary rock In Canadian Basins (NcCrossan and Porter, 1973) salts precipitated by evaporation of sea water and through the agency of organisms which precipitate calcite. In addition to the deposits laid down in the marine environment, non-marine deposits are spreadfay the rivers on the surrounding Ipw-lying land surfaces. An example of a sedimentary regime can be seen in Figure 1 which shows the western Canada sedimentarv basin area as it would appear from the air during the late Devonian time, 350 million years ago. The chain of reefs, near the centre of the illustration, including Redwater and Leduc can be seen cutting off the eastern portion of this basin from the open water-. At the same time as the reefs were growing the basin was filling with muds, banking in from the eastern shore. Intermittent subsidence continued for almost 600 million years after the beginning of the Paleozoic in this general region resulting in a great wedge-shaped slab of sedimentary rocks covering the prairie regions of Canada and shown in Figure 2. It shows the thickness of all the unmetamor- phosed sediment of Canada having some petroleum potential. The thickest, regions shows in darker colors range to over 35,000 feet. You will notice the more central regions of the continent have a thinner sedimentary cover or the Precambrian shield is exposed indicating the more stable nature of that region which in turn explains the poorer quality sedimentary basins wtthin it. Moving away from the craton centre, the sedimentary masses thick- en and in some cases these form much better quality basins for petroleum. For various geological reasons, however, the various sedimentary masses have quite different potentials for petroleum occurrence. Organic matter incorporated in varying quantities in most sedimentary rocks, is of two main types: woody plant materials, made up of carbon, oxygen, and hydrogen; and other organic material lower in oxygen content and having it in less stable forms such as waxes, fats, proteins, etc. The former are derived from the land plants and the latter from marine animals and plants as well as certain parts of terrestrial plants. We shall now examine this organic material in more detail since it is involved directly and indirectly in the formation of almost all of the economically important energy minerals. PETROLEUM Oil is derived from kerogen or sapropelic material in the sedimentary rocks; that is the organic material relatively rick in carbon and hydrogen and low in oxygen. This is the part of the organic complex lacking in the woody material or carbohydrates. It is made up of such things as the waxy coatings or cuticle of plants, resins, lipids or fats, and protein material. Only very small amounts of hydrocarbons are formed in the early stages of deposition, as may be seen in Figure3and it is not until the organic material is buried to at least a 1,000 metres that sufficiently elevated temperatures are attained to generate significant quantities of oil. The subsurface temperature varies from place to place, with variations in the rates of heat flow from the earth and with the insulating quality of the overlying blanket of sediment. This action produces a whole range of hydrocarbon compounds hot shown on the slide. Kith increasing depths of burial and heat these are progressively cracked to simpler compounds of lower Q molecular weight and" size until eventually at temperatures of 125 - 150 Centrigrade, methane is the only hydrocarbon left. At shallow depths small quantities of methane or dry gas are generated particularly from the woody CTs

HYDROCARBONS GENERATED OIL

BITUM.

ROCK

Typt a

FLAT LAKE BITUM 30

ROCK SO

K> Typ*b - e

BITUM ROCK

Figure 3 - Generation of Hydrocarbons with Increasing depth and temperature (after Sokolov et al., 1968) CydanM««6qeta) Figure 4 - Biodegradation it alkanes In Cretaceous oils (Deroo et al., 1973] remains of the terrestrial organic material through bacterial action and which accounts for many gas fields in eastern and southern Alberta. Hydrocarbons are formed in what are called source rocks which are very fine grained usually marine shales, formed from muds deposited in the deeper, quieter parts of a basin where the light organic particles come to rest with the finest grained sediment. As these fine-grained sediments pile up the water is squeezed out of them with increased load. The fluid moves from i,he source rock in the direction of the decreasing pressure gradient or towards the surface carrying the hydrocarbon compounds along with it. When the fluids pass into coarser grained rocks or reservoirs, they are sieved out effectively if the coarse rock is surrounded by a fine impermeable rock since the hydrocarbon molecules once coalesced cannot pass back again into the fine grained sealing rocks, even though the water molecules can. Exactly how this process operates is still not well understood. Once in the pores of reservoir rock the hydrocarbons,being less dense than the saline waters permeating the whole sedimentary mass* rise gravitationally to the top of the reservoir. Traps for hydrocarbons are formed when reservoirs with sealing rocks over them are deformed in structure by mechanical movements which may create folds in the bedded rocks. A closed container or trap can also be formed stratigraphically where a wedge of sand or a buried oyster bank, for example, or perhaps a coral reef, wedges out up the gentle regional dip towards the edge of the sedimentary basin. It must, of course, be closed off at its ends as well. Thus in order to form an accumulation of oil or gas we must have: 1. a fine-grained source rock sufficiently buried; 2. a coarse grained porous reservoir rock; 3. an impermeable sealing rock; 4. a trapping geometric configuration in the rocks; 5. last and often forgotten, but all important, timing - or the correct sequence of events. That is the trap must be in position to receive the oil when it moves. Oil has been forming since the beginning of marine life in the late Precambrian, but by far the bulk of the world's commercial deposits of hydrocarbon occur in young rocks; 29% Cenozoic in the last 74 million years, 57% in the Mesozoic from 200-75 million years and 8% Permian - 200-225 million years and less tnan 6% before that. Only a very small fraction of the total hydrocarbon generated in the source rock is caught and retained by traps as it escapes from ttte sedimentary basin. There is another rather special circumstance under which escaping nydrocarbons may come to rest before reaching the curface and that is the condition under which the heavy oils of Alberta formed and is illustrated in Fiqure 4. Along the updip edge of the Western Canada Sedi- mentary Basin invading surface waters have carried bacteria into the subsurface through the very porous sa^ds of the Lower Cretaceous formations. These bacteria have literally eaten the alkanes or straight chain hydra- carbons out of the oils leaving a residual oil made up only of ring type compounds of much greater viscosity than a norma"1. oil from deeper in the basin. The type of evidence leaaihn to this hypothesis is shown in the chromatograms of a succession of oil samples ranging from a normal oil at HUUIH BAR - COASTAL BARRIER COMPLEX

Figure 5 - Cretaceous landscape with low lying alluvial plain containing coal swamps bordering ancient sea (Morris and Jansa, 1971)

Figure 6 - Thin section of coal from harbour seam in Nova Scotia showing various types of materials (courtesy of A.R. Cameron) Bellshill Lake to a sample from the Athabasca deposit. The normal alkanes and eventual! ypristane and phytane have been removed from the oil in a systematic progression to the basin edge. It has been suggested by Jardine (1973) that this change in physical properties is sufficient to bring the oil to a halt in its movement out of the basin. I think that you can see then that the distribution of the various types of hydrocarbons in a sedimentary basin is quite orderly and to some extent predictable. And now I would like to show you that a similar pattern exists for coal as well. COAL Coal is formed from the other main type of organic material to be found in sedimentary rocks. It can be defined as a combustable rock which had its origin in the accumulation and partial decomposition of vegetation. The organic compounds such as cellulose, lignin, starches and sugars, together with minor amounts of proteins, fats, oils, resins, waxes. The carbohydrates consist of carbon, hydrogen and oxygen and the resins, oils and other plant materials are made of carbon and hydrogen with little or no oxygen. As you will recall these latter types of compounds were the precursors for the oil and gas about which we just spoke but they may also form special types of coal. The proportions of these various materials are one of the main factors in determining the character of the coal formed from them. Lush forests grew under rather special conditions in the geologic past when large volumes of sediment from mountains bordering the ancient seas covering the central parts of the continent formed deltas with vast swampy plains between the sea and the land as shown in Fioure 5. The woody plant materials accumulating in the fresh and brackish waters of this environment formed thick organic layers which partially decomposed through bacterial action until the activity was arrested by a build up of the toxic decomposition products, pickeling the plant material in its own juices. Peat was thus formed just as it is today in many parts of the world. During this process a number of new organic compounds were formed and gases such as carbon dioxide, methane and hydrogen were given off to the atmosphere. As you will recall, it is methane formed by such a process from disseminated plant material that is found in the shallower parts of the sediirentary basin. The peat forming process involves asteady increase in the proportion of compounds rich in carbon. If the decomposition took place in a well oxygenated environment the end product would be only carbon dioxide and other gases. As you can see in Fioure 6, which is a thin slice taken from a coal sample from the Harbour seam in Nova Scotia, coal is by no means a homogeneous black material; rather it is made up of a variety of plant fragments. The dark grey (red in original) material is vitrinite and represents decayed bark and woody tissue impregnated by liquid decomposition products that was transformed into a harden&d gel during the peat formailisn. The light grey (yellow in original) material which happens to dominate in this particular specimen represents-the resins, spore and cuticle material, and is known as exinite and the black fragments are inertinite, probably formed through decay under conditions involving direct contact with the atmosphere, and without a liquid impregnation giving rise to a soft charcoal-like material. The banded nature of the coal with bright and dull ri e pt h The increase of rank of coal ft. m (decrease of volatile matter) IBJU 1

- 2000- •i -

7000- / 2200-

2400-

eooo- /

/ 1 2600- - / 9000- 2800-

3000- / - tooso- 10 20 30'i volatile matter d.a.f.

Figure 7 - Loss of volatHes with depth (Murchison et a!., 1968)

Figure 8 - Composition of coal ranks (Averitt, 1973^ 11 layers can be explained by the fluctuating conditions during the accumulation of the plant material. The peat is considerably reduced in volume by the extrusion of water and volatile compounds containing oxygen. The progressive enrichment in carbon continues and the peat gradually changes to a solid dark true humic coal. Figure 7 is a plot showing the loss of volatiles with increasing depth from a borehole in northwestern Germany. As successive layers of sediment are added like oil, the peat is altered by being cooked and packed under greater and greater pressure to form the denser types of coals of increasing rank ranging from brown coals and lignites, such as are found in Saskatchewan, to sub-bituminous and bituminous, as occur in Alberta and eventually under conditions of extreme temperature and pressure anthracite. This change in types of coal is accompanied by marked differences in chemical and physical properties as is shown for the different ranks in Fiaure H. The black bars indicate the proportion of fixed carbon. It can also be seen that there is a continuous reduction in the proportion of volatile constituents in the coal with an accompanying decrease in the oxygen content to the point where in anthracite, the coal is made up of 95% carbon. These variations in composition and physical properties determine the use for each type. For instance, only certain types of coal having 20-30% volatiles are suitable for making high grade coke. It wasn't until about 300 million years ago that significant quantities of coal commenced to form when the land plants sudden- ly evolved. The carboniferous was one of the main periods of coal formation and the deposits of eastern North America were formed at that time. The other main period of coal formation in North America was in the upper Cretaceous 100 million years ago or so and was related to the period of major mountain building in the Cordillera which provided abundant terrestrial sediments bordering the Cretaceous seaway with extensive coal swamps. Thus it should be emphasized that the conditions suitable for coal formation are rather special and have occurred at only certain times in the geologic past in particular areas of the world with the result that the bulk of the 16.8 trillion tons of estimated world coal resources lie in Asia and North America. URANIUM You will recall that I stated at the beginning of this talk that all the energy minerals occurred in sedimentary rocks. That statement is almost true in that the major uranium deposits of the world also occur in sedimentary rocks in particular Precambrian conglomerates ?nd Mesozoic sandstones. It is not quite true in that the minerals of this element occur in a variety of other ways as hydrothermal deposits, pegmatites, disseminated in granites and so on, but these modes of occurrence are all of lesser importance. The origin of thiae sedimentary uranium occurrences is not well understood but it is probable that the uranium minerals occurring in the Precambrian conglomerates were detrital and formed fossil placer deposits which include other heavy minerals. The major deposits of South Africa are actually mined for their gold content with the uranium being a by-product. 12

Figure 9 - Log-normal distribution of reserves In Leduc reef pools. Alberta (HcCrossan, 1969)

100 CUMULATIVE FREQUENCY PLOT OF WESTERN CANADA 90- OIL AND GAS POOLS

BO-

70-

60-

30- TOTAL NUMSER OF OH FOOLS 1221 TOTAL NUMKK Of CAS POOLS 2472 20-

0 X) 20 30 40 50 60 70 CO 90 400 PERCENT or roots

F1»ur« 10 - Percent of ressrves of oil and gas froa MesUrn Canada vs. percent of pools 13

The most important Canadian deposits are also of this type. The deposits in sandstones of the western United States in which the uranium minerals either fill pores in the rock or replace rock-formTng minerals or carbonaceous material are throught to have been formed from the uranium leached from igneous rocks in surrounding areas. The dissolved uranial salts were transported in ground water in the hexavalent state and precipitated under reducing conditions in the tetravalent state. Again even for these minerals we find that the organic components of the rock are of importance in that they are one of the main agents that facilitate this redox reaction. I have not bothered to discuss thorium since it fs not yet an important, fuel. DISTRIBUTION Another characteristic common to all types of mineral deposits is the way in which they are distributed. For example, the concentration of uranium in the earth's crust is in the order of two parts per million and it is very ubiquitous. Anomalous concentrations of uranium are wide spread but mineable deposits are rare with average concentrations of ,1% and higher. Similarly, hydrocarbons are very common in sedimentary rocks but in trace amounts with on1y a very small fraction of the total subsurface fluids being made up of hydrocarbon compounds. The processes about which we have spoken, however, have concentrated these fluids in anom lous quantities, but these concentrations are distributed in a most irregular manner. Many sedimentary basins of the world are totally Tacking In exploitable deposits, perhaps because they lack only one of the variables necessary for accumulate .n. Within a petroleum-prone basin the distribution of the oil and gas fields is also irregular with many fields clustered in certain areas of the basin where there was a confluence of the necessary conditions for accumulation. One can easily appreciate this irregularity by considering the very large proportion of the world's petroleum resources concentrated in a small area of the Middle East (15% of the world's hydrocarbon reserves in Ghawar and Bergan fields alone). Both oil and gas pools and mineral deposits display a size- frequency distribution that is approximately log-normal. Fiqure 9 shows the distribution of sizes of the Leduc reef pools of Western Canada. The middle graph is a log probability plot of these data with each dot representing an individual pool. With this type of distribution a very few pools contain the bulk of the hydrocarbon. For example, Redwater the largest pool in that particular distribution contains 817 minion barrels of oil recoverable and is by definition a giant and the only one in the set. That one pool contains 31% of all of the Leduc formation oil reserves which are distributed over 53 pools. The largest five pools in the upper tail of the distribution contain 75% of the 2.7 billion barrels of oil reserves in this system. That is 10% of the pools contain 75% of the oil. 90% of the oil lies within the top 9 or 17% of the pools. Figure TO shows the total oil and gas reserves of western Canada as a cumulative plot with percent of pools on the abscissa and percent of reserves on the ordinate, The graph shows very clearly that the last few percent of the pools contain a very large percentage of the total reserves. Finally it is worth noting that 65% 14

of the world's hydrocarbons occur in 1% of all fields; the 55 supergiants (McCulloh, 1973). When we consider that the largest pools or mineral deposits are often the easiest to find once the geological concept has been identified, it is not difficult to appreciate some of the economic and sociological problems that have arisen in the past in exploiting the world's mineral resources. On a free market, the discovery of the elephants can seriously disrupt price structures and make exploration for and exploitation of smaller accumulations uneconomical. ESTIMATES OF MINERAL RESOURCE POTENTIAL While I anticipate that the other speakers on this program are going to deal with resource potential in some detail, I would like to try to clarify an important concept that still seems to be somewhat confused at least in the popular press; and that is the difference between reserves and resources. Reserves are already found and while the estimation of the quantities discovered may still be a rather inexact science, they are tangible and recoverable at a profit. Resources, or future petroleum potential, on the other hand, are working geological hypotheses; and not less valuable for that. They are as good as the background information upon which they are based. With a thorough understanding of the geology there is no reason to suppose that shrewd estimates of what lies ahead are not possible. Over the years the data collected throughout the world or. oil occurrence in the course of extensive exploration must form the largest body of scientific information ever accumulated about the earth's crust. Surely geologists should be capable of exploiting this information to tell us a good deal even in a quantitative sense about what remains to be discovered. To those who have decried these efforts, I say, make your criticism constructive and con- centrate on the merits of the geological arguments and not generalizations and emotional issues. CONCLUSIONS The sediment accumulating within depressions in the earth's crust contains within it small but important quantities of organic material. The two basic types of this material with burial and increasing temperature form coal and hydrocarbons respectively. When certain basic geological conditions necessary for the accumulation of mineral deposits or oil pools coincide a commercial accumulation may result. Only rarely are all the conditions optimum and when present can result in giants. The combined probabilities of these events results in a log-normal probability distribution. 15

REFERENCES Adams, P.J., 1960, Origin and Evolution of Coal, Geological Survey of Great Britain, 17 P. Averitt, Paul, 1973, Coal, jr[ United States Mineral Resources edited by Brobst, D. A. and Pratt, W.P.: U.S.G.S., Prof. Pap.820, P. 135 Deroo, G., Tissot, B., McCrossan, R.G., Der, F., 1973, Geochemistry of the Heavy Oils of Alberta, Paper presented at^Oil Sands of the Future Symposium, Can. Soc. Petrol. Geol., Calgary Jardine, 0., 1973, Oil Sands Occurrences of Western Canada, Paper given at Oil Sands Fuel of the Future, a symposium, Can. Soc. Petrol. Geol.s Calgary McCrossan, R. G., 1969, An Analysis of Size Frequency Distribution of Oil and Gas Reserves of Western Canada, Can. Jour. Earth Sc, V. 6, P. 201-211 McCrossan, R. G., and Porter, J.W., 1973, Geology and Petroleum Potential of Canadian Basins in: Future Petroleum Provinces of Canada, Can. Soc. Petrol. GeoL.TIem. 1 in press McCulloh, T. K., 1973, Oil and Gas Vn_ United States Mineral Resources, U.S. Geol. Surv., Prof. Pap. 820, P. 481 Murchison, Duncan and Westoll, T. Stanely, 1968, Coal and Coal Bearing Strata, P. 237, Oliver and Boyd, London. Nelson, S. J., 1970, Face of Time, Alberta Soc. Petrol. Geol., P. 104 Norris, D. K. and Jansa, L.F., 1971, Cascade and Crowsnest Coal Basins: Geol. Soc. Am., Rocky Mountain Section, Field Trip Guide Book.

Sokolov, V. A., Bujiiat-Zade, Z.A., Goedekian, A.A.s Dadashev, F.G., 1968, The Origin of Gases and Mud Volcanoes and the Regularities of Their Powerful Eruptions im Advances in Organic Geochemistry, Pergamon Press, Oxford, P. 477, 17

POTENTIAL OIL RESOURCES AND THF.IR DEPENDENCE ON PRICE AND GOVERNMENT SHARE

By D. K. McIVOR aid-D. D. LOUGHEED Imperial Oil Limited

In the early 1980's Canada will require additional supplies of domestic crude oil to meet its demand. Canada has significant potential crude oil resources; however, potential oil resources do not become reserves and appear in the consuming market until they are discovered and developed. This paper discusses Canada's potential oil resources and describes how their rate of development is dependent upon price, government share, markets and other factors. While the paper primarily discusses potential crude oil resources, the principles apply equally to the development of potential natural gas resources. The discussion which follows will start with a description of the methodology of assessing petroleum resource potential. Next the factors which influence the incentive and timing of the exploration and development of resources will be discussed. Then, using a simple mathematical model of a hypothetical frontier petroleum basin, the effect of some of these factors will be discussed in a quantitative fashion. Finally, the foregoing will be placed in the context of Canada's Future crude oil requirements. THE ASSESSMENT OF POTENTIAL OIL RESOURCES An analysis of the effect of various factors upon the exploration and development of potential crude oil resources requires first that we establish some appreciation of the producible oil potential. This is not easily accomplished, as evidenced by the wide variations among recently published estimates. The difficulty lies in the numerous highly uncertain fortors that control oil occurrence and the fact that knowledge of these factors varies widely from one area to another. Thus, to obtain a proper appreciation of the potential oil resources, one must accept the concept of dealing in ranges of potential reserves and understand that the confidence level or magnitude cf the range is proportional to the state of knowledge for any given area. The initial assessment in a new basin will of necessity be very crude. An estimate of the volume of sediments will be combined with an estimate of their richness, derived from the surficial knowledge of the sediments and comparison with known oil producing areas elsewhere in the world. As the exploration process proceeds through the geophysical survey and drilling stages, increasing amounts of "hard" data related to the 18

critical factors of reservoir rocks, source rocks, traps, and preservation from destructive events will allow progressively more intelligent and accurate assessments of the oil potential. A spectrum of assessments will be generated, varying from a wide range estimate for virgin basins to a relatively narrow range estimate for mature productive basins; and these will continually change as subsurface information and knowledge accumulates from geophysical surveys and drilling. For communication purposes, the probability concept is very useful when dealing with ranges and judgments. In this approach the range in estimated potential reserves is related to varying probabilities that specific amounts of potential reserves are present. This procedure carries with it the facility to sum numerous probability distributions of varying character to achieve a total probability distribution. In this way probability distribution curves for all the various basins within Canada can be summed to provide a probability distribution for all of Canada. Since we use probabilities and know assessments are continually evolving, potential reserves estimates should be recognized as directional rather than factual. As such they can serve to direct policy and exploration intelligently but only by thorough exploration can one establish whether the assumptions and judgments are correct. In the context of these general comments it is our view that the estimates prepared by the Geological Survey of Canada (GSC) and quoted in "Energy Policy for Canada - Phase I" (Reference 1) constitute a reasonable assessment of the potential undiscovered crude oil resources of Canada. However, all assessments tend to put some potential reserves everywhere, suggesting widespread oil occurrence rather than the very unevenly distributed occurrences found in nature. Thus they likely do not present the true picture of the risks and uncertainty involved in searching for oil. With these reservations, what does the GSC assessment tell us? Following are some of the highlights: - The mean probable potential for conventional crude oil resources for Canada is about 100 billion barrels. - Of this 16 billion barrels* have already been found, essentially all in the Western Provinces. - About four billion barrels of crude oil remain to be found in the Western Provinces and because it will likely occur in small pools, it will be difficult and costly to find. - About 80 billion barrels of Canada's undiscovered oil potential is located in frontier areas. *Includes natural gas liquids 19

- Of the frontier potential 63 billion barrels is located offshore, much of it in areas where the technology to explore and develop does not yet exist. In summary, Canada is estimated to have a relatively large undiscovered conventional crude oil potential, more than five times what has been found to date. Almost all of this lies in the remote frontier areas, many of them in very hostile environments. Finding and developing this potential will be difficult and costly and much of it may never be developed without the incentives of increased price, assurance of markets and a reasonable share of the reward between the public and the investor. FACTORS INFLUENCING THE INCENTIVE AND TIMING OF THE EXPLORATION AND DEVELOPMENT OF RESOURCES The geological assessment procedure has established a mean undiscovered crude oil potential of about 84 billion barrels of oil; but, it must be emphasized this does not constitute a marketable resource until it is found, developed and provided an access to market. The incentive to do this is influenced by the geological risk, government share and stability of associated regulations, prices, markets, transportation costs, well productivity, etc. Since these factors are so pertinent to the ultimate materializa- tion of potential resources, this Section will discuss how each factor influences exploration/production incentive as background for the next Section which will present a numerical demonstration of their role. Oil Occurrence Risk One of the basic factors influencing exploration incentive is the high risk attached to finding significant quantities in any given area which in turn is due to the unequal distribution of oil and gas in the earth. Oil and gas occurrence statistics show that these commodities are extremely unequally distributed throughout the sedimentary basins of the world. A very few are extremely rich, more are modestly rich and the great majority are very lean or barren. Even within relatively rich basins, the oil and gas is usually concentrated in a very small portion of that basin. There are in the order of 500 sedimentary basins in the world, although the number is somewhat arbitrary since the separation between one basin and the next is often indefinite. Over half of the oil and g«s reserves discovered to date are contained in three of these 500 basins - the Persian Gulf, West Siberia, and Gulf of Mexico basins. A few score basins have significant reserves (more than 5 billion barrels, including gas converted to oil-equivalent). Reserves of more than local significance will probably never be discovered in most of the remainder. Reserves within a single basin are similarly uuequally distributed as can be documented by analyzing any mature exploration area. For example, Figure 1 illustrates !~ow the known oil reserves of Western Canada 20

WESTERN CANADA 800 CRUDE OIL POOLS RECOVERABLE RESERVES BILLIONS OF BARRELS 0.5 1.0 1.5 2,0 3 PEM6INA SWAN HILLS 3 REDWATER ^JUDY CREEK HILLS S. T&'Jiit BONNIE GLEN WIZARD LAKE THESE rav#fo&rt MITSUE POOLS COHTAIH ASffvaffa WEYBURN 50% + 11113 NIPISI OF AGGREGATE gWftl GOLDEN SPIKE RESERVES [M^IFENN ^.^'4^,'3 LEDUC - D3 SHHl BOUNDARY LAKE

i VIRGINIA HILLS CARSON CREEK _J STURGEON LAKE KEG RIVER 'B1 WILLESDEN GREEN AGGREGATE PROBABLE TURNER VALLEY ULTIMATE RESERVE KAYBOB - BHL 14 BILLION BARRELS WESTEROSE (EXCLUDES NATURAL GAS LEDUC - D2 LIQUIDS ) ACHESON - D3 KEG RIVER F 775 * POOLS < 100 MM BBLS.

FIGURE I 21 are distributed. More than half of all the discovered reserves are seen to be located in 15 pools, out of a total of 800. A similar picture results from an analysis of gas reserves. The reason for this extremely erratic distribution lies: in the complex interplay of geological events that must occur in order to provide an oil wr gas pool. The absence of just one of several critical factors precludes an accumulation. Looked at from this perspective, the many estimates of oil and gas potential within Canada's frontier basins may be misleading in that they generally imply significant reserves virtually everywhere and thus tend to minimize the risk involved in locating them. Canada's undiscovered hydrocarbon reserves will be distributed like those elsewhere - concentrated in a few basins, and further, in restricted parts of those basins. In this context it can be seen there is considerable risk in predicting even the presence of oil. Our confidence in the assessment estimate of 84 billion barrels of undiscovered oil in Canada must be based on the premise that the volumes and types of sediments within Canada are so vast that on the average it is reasonable to expect this amount of oil. In reality some basins will have more than the estimated potential and some will have none. Every explorer will have his own assessment of a basin and the realization that it will be unevenly distributed, both as to location and pool size, points out the risks as to the time that such resources will be available to the market and consequently the lengthy lead- times inherent in the oil exploration process. Government Share Government share of revenue has two effects: it reduces the potential reward and therefore the incentive to explore; and it lowers the cash flow available to the explorer for investment in exploration and development. Accordingly, if the government's share is high only the more highly assessed areas and those where exploration is less expensive are explored. We wish to discuss next a number of measures through which government share of revenue or its equivalent is obtained from the resource explorer, (i) Taxes The various levels of government receive revenue of different types from exploration/production activity: e.g. municipal taxes on property, plants and equipment; royalties, lease bonuses and rentals; licences and fees; and income tax. We intend to discuss only income tax here; however, in 1972 governments received $381 million from non-income te petroleum sources. Income tax for all corporations is calculated by applying a taxation rate to a taxable income. The taxation rate for petroleum exploration/development operations is about 50%. This compares to the current tax rate for manufacturing and processing of about 42%. Taxable incdme for the current year is obtained by deducting EXPLORATION/PRODUCTION COMPANY INVESTMENT & GROSS REVENUE PROFILE

GROSS REVENUE

-2 5 10 15 20 25 YR. NET CASH FLOW & BOOK PROFIT PROFILE

TOTAL GOVT REVENUE

NET CASH FLOW fron; production revenue a number of allowable expenses incurred during the taxation year or carried forward from the preceding years. Some examples are: - Losses - Capital cost allowance on expenditures for fixed capital assots such as field equipment, gas processing plants, etc. {The deduction rate, applied on a diminishing balance basis, varies from 5% to 30% per year depending upon nature of the asset.) - Exploration expenditures (geological and geophysical exploration surveys, exploration wells, land rental, applicable wages, salaries, etc.) - Production expenditures (development well drilling expenditures, fuel, applicable wages, salaries, etc.) The sum of these deductions when subtracted from production revenue after royalties yields net income before depletion. If there is not sufficient revenue in the current year to cover exploration and development expenditures, they may be carried forward to future years when such revenue does exist. The final step is the deduction of the depletion allowance from net income before depletion to obtain taxable income. An incentive in the form of depletion allowance has been available in Canada for extractive industries since a tax on corporate income was introduced in 1917. Initially the depletion allowance recognized the exhaustible nature of non-renewable natural resources. Subsequently it became recognized that this return of funds to the business promoted exploration to replace depleting resources ant to some degree compensated for risk. Tax legislation changes passed in 1971 changed the manner in which the.depletion allowance is calculated. The general result of the new legislation is to reduce the depletion allowance, thus increasing the government share. This is reflected by the change in effective income tax expressed as a percentage of net income before depletion. For example, prior to 1977 the effective income tax rate is always 33 1/3% of net income before depletion. After 1977, the effective tax rate will vary between 33 1/3% and 50% of net income before depletion, depending on the level of exploration. For any company with significant production income, the rate will be close to 50%. The income tax share of revenue over the life of petroleum ventures is very significant. Figure 2 has been prepared to illustrate a representative expenditure/revenue profile for a successful petroleum exploration/development company, in the Western Canada basin arid to depict the revenues accruing to governments and shareholders over time. 24

We have assumed that this company will spend $10 million over its investment phase, half on exploration and half on development. By Year 7 when initial production is achieved, the company will have accumulated almost $5 million of expenses which may be deducted from production revenue when calculating income taxes. Over the next 4 to 5 years, this backlog of prior expenses or losses is reduced to zero and income taxes become payable in Year 12. Revenues begin accruing to governments from the beginning. Industry-average data show that Provincial Governments would receive over 40% ($2 million) of this company's exploration outlays in the form of lease bonuses and land rentals. Royalty payments commence with production in Year 7 and rise rapidly as production rates increase. These two revenue sources have been added to income taxes to give the Total Government Revenue line shown. Typically, new exploration/development companies adopt the full- cost accounting method for shareholder reporting. All exploration/development expenses are capitalized and considered as assets, rather than booking them as charges in the years they are incurred. These capitalized expenses are then amortized (written off) against revenues over the life of producing properties. The net effect of this approach is that companies will report book profits to their shareholders well in advance of having recovered past expenses and being in a taxable position. Book profits ir the example of Figure 2 commence in Year 7, some 5 years ahead of having achieved a true break-even postion. Of course, over the life of the company the cumulative net cashflow and book profit are equal. It should be nov.ed that for each $1.00 of book profits, governments will receive $1.18, indicating an effective share in excess of 50%. In other words, cumulative government revenue exceeds cumulative net cash flow and cumulative book profit. This example demonstrates the fallacy in judging the petroleum industry's contribution to the economy only in terms of income taxes over a limited time frame. Some critics refer to low apparent income tax rates without recognizing that most industry members are only now in the position of having largely recovered past exploration/development expenses and operating losses. In a notional sense, the shape and timing of the expenditure/revenur'taxation/book profit curves for the industry is similar to that for the single venture shown in the Exhibit. Thus, industry as a whole in Western Canada may be thought of as being situated at about Year 12, i.e., it is only now at a break-even position and becoming taxable. (ii) Royalties A royalty is a share of production of oil or gas retained by the lease owner who, with the exception of some freehold land in Southern Canada, is usually a government. It is not a tax. The royalty share must be given to the lessor free and clear of operating charges. It has commonly been 1/8 or 1/6, though governments have granted a reduction for wells producing below a specified rate. Recently Alberta and Saskatchewan have increased the oil royalty rate to 25% and British Columbia has increased theirs to 40%. This is in contrast to most 25 jurisdictions where royalty rate was constant for the term of the lease and any renewals if production ^tinues beyond the original term. On Federal land in Canada's high exploration cost frontier areas, to provide exploration incentive, the Government of Canada set a royalty rate of 5% for three years and 10% thereafter on the permit holders' initial lease selection. These rates are under review. (iii) Lease Pattern Selection Regulations After making a discovery on Federal and most Provincial lands the explorer is not allowed to retain all the acreage in his permit. He must surrender half to the Crown according to a kind of checkerboard pattern and this means the explorer loses the portion of his di uvery which underlies the surrendered lands. Thus the government obtains a share of the reserves which falls somewhere between zero and 50 per cent of the discovery depending upon pool size and the lease pattern selection regulations. The land retained by the explorer is termed primary acreage; that surrendered is called corridor acreage. Lease pattern selection regulations of this type are unique to Canada. Portions of permits in other world jurisdictions are also frequently relinquished to governments but not until reserves have been defined and not in a checkerboard pattern. Thus parts of discovered pools are not relinquished to government. In the case of Federal lands, Land Order 1-1961 permitted the original permit holder to reacquire the corridor acreage by accepting a higher royalty rate which varied from 20% on oil in the Mackenzie Delta, for example, to 50% on oil in the less remote southern Northwest Territories. The Land Order was rescinded in 1970 and government policy with respect to corridor acreage is currently under review. This has created uncertainty in industry planning at a time when major expenditure commitments have been made and new ones are pending. (iv) Bonus Payments to Governments for Land Acquisition There are two types of bonus transactions in the industry which relate to the exploration and development of oil and gas. The first relates to Provincial Crown reserve land which is offered for sale by requesting cash bonus bids. Future production from this land is, of course, sMll subject to a royalty. Since this type of land is near or adjacent to a known oil or gas field, the risk of failure is much lower than when the land was an unexplored permit. Accordingly, it will attract relatively high bids. The sale of Crown reserve land has been a lucrative source of revenue for the Western Provinces. For example, over the period 1947-1971 the Province of Alberta received $1.3 billion from sales of Crown reserve land. It should be recognized that the reserves which, under the lease selection regulations, revert to the Government represent a form of exploration disincentive, since the original finder took this loss into 26 POTENTIAL RESERVES ASSESSMENT FRONTIER OIL VENTURE 100

co LLJ or LLJ CO

60 \ co

\ cc

I 40 \ QQ IAN * 2.5 B LLION BBLS CO ce Q_ L \ \ 20 S

I 2 3 4 5 6 7 8 9 10 II I?. 13 POTENTIAL RESERVES - BILLION BBLS FIGURE 3 27 account in his economic assessment of the venture. The second type of cash bonus involves a competitive bidding procedure to obtain an exploration permit for unproven lands. The system has been used in the Provinces and has been proposed for the frontier areas. Its institution would result in a disincentive to exploration because it is an added exploration cost. In addition, it would not result in the generation 0* significant government revenue, because exploration permit acreage is high risk land. Price It is common in economics to find that higher commodity prices bring forth added supply and it is not surprising that this holds true for crude oil. For example, the Western Canada basin has potential undiscovered oil reserves of four billion barrels. This will likely be difficult and costly to find because it will be found in small accumulations; but, higher prices will provide an additional economic incentive for exploration and development of these reserves. The frontiers, as we have noted, are estimated to contain 80 billion barrels of Canada's undiscovered oil potential, of which 63 billion barrels is offshore. The remoteness and the hostile environment of these areas mean higher exploration, development and operating costs. Price can easily determine whether or not a given basin will be explored or whether pools of a given size or productivity can be economically developed. This will be addressed quantitatively in a later section. Another feature of the frontiers is their remoteness from the point of sale in the consuming market. The producer receives the market crude oil price less the transportation tariff between the wellhead and the market. Because remoteness from markets means higher transportation tariffs, exploration prospects must be better to offset the additional transportation expense. Market The assurance of markets is as important a component of exploration incentive as are good geological prospects and the expectation of adequate prices. A key feature of a favourable market outlook is the opportunity to produce reserves at economic rates. This means exporting supply that is surplus to domestic requirements. Energy Policy for Canada - Phase I has documented Canada's need for additional supply in the 1980's. To meet this requirement Canada should always have surplus domestic productive capacity to which it can turn as Western Canadian conventional crude oil productive capacity declines. The timing of exploration discoveries cannot be predicted, yet the realities of exploration economics dictate that the explorer must be able to market new supply as soon as it can be developed. Thus a market system which provides the opportunity to export surplus supply is a key factor in the conversion of potential resources to proven reserves. 28

POOL SIZE DISTRIBUTION FRONTIER OIL VENTURE 900

- 100

t/s 600 80

tif / - 60

300 40 5 J/ Uj 1 -— 20

0 C D E F G H POOLS FIGURE 4 29

ILLUSTRATION OF HOW OIL OCCURRENCE RISK, PRICES, COSTS, AND GOVERNMENT SHARE AFFECT THE EXPLORATION DECISION PROCESS In this Section, we will follow the thought processes and analyti- cal economic evaluation of a typical Industry explorer as he considers a new exploration venture. The example is hypothetical, but uses parameters evolved by Imperial in exploration planning and evaluation in Canada's frontiers. The example depicts exploration economics in an ice covered environment. An onshore frontier situation with lower per well exploration costs could have been used; however, the potential reserves assessment of the venture would also have been lower. The case chosen better depicts the economic decisions facing explorers in the offshore frontier areas where the bulk of Canada's potential oil is expected to lie. It is assumed the explorer is satisfied as to availability of markets and the price outlook. It is also assumed that a large block of prospective acreage is under permit to a single explorer, although this is not usually the case. Basic Description After land acquisition, primary seismic evaluation is conducted. This will define the number, size, and type of structures on the explorer's acreage. In the example, it has been assumed most of the major structures have been identified before the start of exploration drilling. Potential reserves are estimated from the size of the structures, a risk assessment as to the number that might contain oil, and reasonable assumptions for reservoir thickness, per cent of trap filled, and recovery factor. Potential reserves in the assumed oil-containing structures of the hypothetical venture have been expressed in terms of probability as shown on Figure 3, with ;he "mean" assessment for the amount of oil trapped in the structures being 2.5 billion barrels. Geological and geophysical reconnaissance and historical data from similar basins are combined with the mean assessment to construct a pool-size distribution curve (Figure 4). Note the explorer expects the five largest structures, Pools A through E, will contain about 90% of the potential mean reserves assessment. At this stage of exploration, it is not known whether the basin contains any oil, so the explorer defines the minimum diagnostic exploration program he believes will either find the first field or confirm, with reasonable certainty, the absence of commercial quantities of oil. It is assumed that the venture is in a hostile ice-covered offshore environment, and that a special drilling vessel is required. It has a fixed operating cost of $20 MM per year and variable costs of $4 MM per well, and can drill a maximum of two exploratory wells per year. It is estimated that 10 exploratory wells will be required to establish with certainty that the basin is devoid of economic hydrocarbon accumulations, and that the project should be abandoned. This "dry-hole 30

program" will require the expenditure of $140 MM over five years. However, since this exploration program is predicated upon finding a new field, the costs of additional follow-up exploratory drilling to adequately define the venture's potential must also be estimated. This "success case" is assumed to consist of the initial 10-well program, plus an additional 12 exploratory wells, with 8 of the 22 resulting in the discovery of new fields. In addition, 14 delineation wells will be required, for a total success cost of $480 MM, spread over 10 years. This represents an acquisition cost of 19<£ per barrel, compared to the long-term average acquisition cost of 40

POOL ECONOMICS- FRONTIER OIL VENTURE

PROFIT , 5 POOLS 334 LESS EXPLORATION COST (AFTERTAX) DRY HOLE PROGRAM... 53 SUCCESSFUL FOLLOW- UP PROGRAM _62_ 115 PROJECT PRESENT VALUE PROFIT AT 10% 2\g PROJECT DCF RETURN ... 14%

PROFIT (EXCLEXPL COST)

FIGURE 5 pool. Note that the ordinate is labelled "present value at 10%." This discount value is chosen because it represents the minimum rate of return most firms would wish to receive on a venture with a low risk. The pool for which the present value of the future income equals the present value of the costs (operating, development, income tax, royalty) is the reserve volume which just yields a DCF return of 10%. In this system, pool F approximately meets this criterion. Pools A, B, C, D,and E, which are larger than F, will yield returns greater than 10%, and thus are indicated to have a present value profit. The expected present value profit from th^ five largest pools (excluding any exploration costs) totals $334 MM, while the present value cost to the explorer of the $140 MM dry-hole program is $53 MM. Thus, the potential present value profit from this venture might be expected to support approximately six similar dry-hole programs and still yield a 10% DCF (334/53 is approximately equal to 6). This is referred to as the "success odds". The success-odds concept was devised as a means of incorporating risk in exploration economics. The principle on which it is based can be explained by the following analogy: In a game of chance there is a silver dollar hidden under one of six inverted cups. Since there is one chance in six of winning the silver dollar in one try, no more than 16 2/3<£ a turn should be risked in order to break even. In the long run, the correct cup should be overturned an average of once in every six tries. This principle applied to exploration recognizes that oil and gas will be found in only some of the ventures. Productive systems must bear the expense associated with unsuccessful exploration. Referring to Figure 5, in our example, the total present value exploration cost is $115 MM, including the successful follow-up program. Thus, the project present value profit amounts to $219 MM, which is equivalent to a DCF return of 14%. Each explorer has some view as to what his DCF target should be, and some view of the probability of there being specific amounts of oil in the basin. How should the explorer view the DCF return and relate it to potential reserves in making his go/no go business decision? In practice, it is difficult to define what will likely be the explorer's lower limit for an acceptable DCF return. Note from Figure 5 that the DCF return is 14% if the explorer finds and develops 2.25 billion barrels (pools A, B, C, D, E). If he considers a 10% DCF return his minimum acceptable target, should he regard the 14% DCF return from this venture acceptable, considering he does not know there is any oil in the basin, and considering his successful 34 EFFECT OF VARIATIONS IN ASSUMPTIONS ON PROFIT

BASE CASE $I.OO/BBL PRICE INCREASE $I.OO/BBL. PRICE DECREASE —

(EXCL. EXPL COST)

FIGURE 6 35 ventures must bear the cost of the unsuccessful ventures? Even when the success odds are relatively favourable, he knows that the economic analysis and results imply a level of knowledge and precision which is not there. They are based on a fabric of "ifs": _If_ there are source beds, geologic structures, and seal beds; if the mean potential reserves and the pool distribution curve is as forecast; if he meets the timing forecast of discovery and development of pools A, B, C, etc.; if the crude oil price outlook is realized; if government royalty and taxes remain as assumed; if there is the market he anticipates; if there is a pipeline, if it is built when pool A is ready; and so on. The explorer's experience tells him if he aims at 15 to 20% DCF return for each exploration venture he should, over a number of years, obtain an average return level which should finance the inevitable future failures. At the same time the expected present value profit must provide success odds commensurate with the assessment of risk. Once the explorer is successful in finding his first economic-size pool in a new basin, he can lower his DCF return target because one of the tnajo^ uncertainties has now been removed — he knows there is oil (or gas) in commercial quantities in the basin. He will still plan a dry-hole program in seeking the second and subsequent pools, and will compare this present value cost, plus that of development and operation, against the present value of the revenue stream. Because there is still significant risk of variability in the pool size and fill, his DCF target must still be well above that for a relatively low-risk venture (10%). Effect of Price on Reserves Explored For and Developed We have seen how the explorer uses economic studies and financial criteria to guide his decisions as to whether or not to explore in a basin. These examples were based upon certain assumptions. One of these was price, and this was assumed to be $2.50 per barrel at the wellhead in 1973, escalating at 5% per year. Higher prices increase potential oil resources in two ways: First, they increase the DCF return of the project. For instance, a $1.00 per barrel price increase applied to the hypothetical system enhances the present value profit of the five largest pools by $320 MM (Figure 6 ) and increases the DCF return from 14% to 22%. The economics resulting from this higher price would probably be sufficient to bring about a commitment from an otherwise hesitant explorer. Second, they permit the development of pools which were uneconomic at lower prices. When the explorer finds oil (or gas) in a basin, he develops only those potential additional pools in the basin which meet his DCF return target. Thus, in the example, a 1973 price of $2.50 per barrel at the wellhead (escalating 5% per year) permits the finding and development only of pools A, B, C, D, and E. A 1973 wellhead price of $3.50 per barrel (also escalating 5%per year) would permit development of smaller-size pools 36 EFFECT OF VARIATIONS IN ASSUMPTIONS ON PROFIT 360 BASE CASE NO GOVERNMENT SHARE 320 1500 B/D/W PRODUCTIVITY

280

240

3? 2 200

160

120

c POOLS FIGURE 7 37 such as F and G, thus increasing the economic supply potential of the venture. Conversely, a price expectation which was $1.00 per barrel lower would completely eliminate any incentive for exploration and development of this venture since the projected DCF return would be only 8%. Effect of Government Share on Reserves Explored for and Pavel oped Just as crude price levels affect present value profit and hence reserves developed, the government share affects the sane factors. Figjre 7 shows a curve of present value profit on the basis of no government share. The difference between the upper two curves is the present value of the government's revenue from royalty and income tax. For the five pools, this exceeds the present value of the producer's profit by a factor of 1.5. It is apparent that by changing its share, it is within goverments1 power to significantly increase or decrease the producer's net cash flow or profit expectations, and accordingly, to affect the explorer's decision to enter the venture. Similarly, by maintaining long-term stability in regulations affecting its share the government can do much to enhance the exploration climate. Effect of Well Productivity on Economics Another key to the economic success of a venture is the productivity of the wells. In our example, it was assumed development wells would produce 3,000 barrels a day. If well productivity was only 1,500 barrels per day, twice the number of development wells would be required. The additional investment significantly reduces the present value profit (Figure 7) and the overall DCF return of the project is reduced from 14% to 11%, definitely too low a return to cover the risks involved. Frontier Crude Oil Reserves Availability as a Function of Price We have discussed the significant effects of price on the potential supply of oil from an exploration venture. We will now extend this concept of supply as a function of price to the frontier areas in total. In the case of the exploration venture, the incentive is provided by the economics of finding oil in pools of varying sizes. We would expect the average pool to be economic at the time of initial development. If this transpires, the bulk of the reserves in the basin would be market-available at about the same price. But the price at which reserves become market-available varies widely among basins. Because of differences in geographical location and hostility of environments eachbasin becomes a distinct economic entity with its own explorationy development and transportation costs. The market price required to bring out supply from these entities must be sufficient to offset transportation tariffs and provide the explorer with economic incentive for exploration and development. Thus, for any area, there is a reserves threshold below which the unit cost of transportation escalates very rapidly and is excessive in relation to any reasonable market price outlook. This is illustrated on Figure S. Point X is the reserve level at which there exists the required combination of market price and transportation tariff providing economic incentive for exploration and development. 38

t \ \ \ \ \

RESERVES THRESHOLD REQUIRED TO SUPPORT A TRANSPORTATION SYSTEM

MARKET AVAILABLE RESERVES I CUMULATIVE) FIGURE 8 »WWIBWI»W«(i«W»0iasaMMM»H»«^^ ^Ti6[iHM^^

CRUDE GIL RESERVES AVAILABILITY AS A FUNCTION Of MARKET PRICE

10 20 30 40 50 60 MARKET AVAILABLE RESERVES - BILLION BBLS FIGURE 9 TIMING OF FRONTIER RESERVES AVAILABILITY

1980 1990 2000 2010 YEAR FIGURE 10 41

To the left of X, the effects of the escalating transportation tariffs are seen in terms of required market price. The plateau price will make the bulk of the reserves in the basin available. The remainder of the reserves in the smaller accumulations will require significantly higher prices to ensure their availability. Thus the price curve rises to the right. Figure 9, which shows how Canada's future frontier oil reserves depend upon price, was derived using this concept. With the GSC assessment of 1973 as a basis, the frontier basins were split into ten logistical areas. Price/market available reserves plots similar to Figure 8 were prepared for each area and cumulated versus price. The hachured area on Figure 9 encloses the resulting range of values. With the current market prices in the range of $4 to $5 per barrel, depending upon crude oil quality, this analysis indicates directionally that between 5 and 15 billion barrels of Canada's undiscovered potential may become available at current prices. An additional 25 billion barrels may become available with prices ranging to $8 per barrel (1973 dollars). The remainder will require higher prices. Even with the expectation of higher prices, there are significant technological problems to be solved before exploration and development of much of Canada's undiscovered crude oil potential will be feasible. Not knowing when this technology will be developed, it is hazardous to attempt to place this forecast of market-available reserves within the cont&xt of time. With this caveat, Figure 10 shows our estimate of the earliest time when frontier reserves could be placed on stream assuming no constraints. The various areas of differing costs have been broken out. with area A being the least costly and area I the most costly. To provide incentive for explorers to find and develop the latter increment, the lead time between the start of exploration and materializa- tion of these resources requires that the expectation of this higher price be apparent now. The plot suggests the technology for making most of Canada's potential reserves market-available could exist by 1995, but the other necessary ingredients for realization of this scenario are appropriate levels of price, market and government share. SUMMATION Let us briefly recap the major points we have presented: 1. Canada is estimated to have a relatively large undiscovered conventional crude oil potential about equal to five times that discovered to date. 2. Canada's undiscovered reserves will probably be concentrated in a few basins and in restricted parts of those basins. 42

3. This uneven distribution is the cause of the risk involved in assuming thac oil will be discovered wherever it is explored for and in predicting the time of discovery, 4. It is also the prime reason for the significant lead time between the start of exploration and the discovery of commercial quantities of crude oil. 5. Major components of Government's share are income tax, royalties, and the portion of a discovery it receives on surrendered land. 6. The explorer/producer's incentive to explore for and develop crude oil depends upon: - Geological prospectiveness and the risk of not finding oil in commercial quantities. - His expectation for the price of crude oil at the wel1 head. - His expectation of government share. - Ths expectation he will be able to market his crude oil, making a reasonable allowance for the time required to provide a transportation facility. - The discounted cash flow rate of return on his investment. - The development of the necessary technology.

DISCUSSION Using these points and the preceding material as background, there are a number of areas on which we believe additional comment is pertinent. It has been argued by some that the distribution of economic rent from crude oil and natural gas production is inequitable; i.e. that the explorer/producer's present value profit is too high, especially in the case of large pools. The explorer/producer's anticipated return should be viewed as the aggregate of successful and unsuccessful exploration with the discovery of both large and small pools, not simply as the result of finding a single large pool. Our analysis of the Canadian oil and gas exploration/ production industry reveals that it will earn only a 10 to 12% DCF return on all its investments in Western Canada. This estimate takes into account the production of remaining reserves at significantly higher prices. Of course, this is an average DCF return for all companies. Some have been \iery successful, but many have made a modest return, and 43

about the same number have yet to recover their costs. With respect to the fortunes of a very successful firm, it is interesting to note that even if one company had been fortunate enough to have acquired the reserves of the six best Alberta pools found in the early 1950's and then terminated exploration, it would have earned a DCF return of about 24%. It is inevitable that some explorer will find a large field on which he will realize a high DCF return. Indeed it is the expectation of individual companies that they will make a better than industry average rate of return that maintains their interest in high risk exploration. It is just as inevitable that the same explorer will have to support earlier or later exploration failures. The matter of exploration lead time has been mentioned several times- A concrete example is Imperial's exploration in the Beaufort Basin. Significant exploration expenditures began in 1964, and resulted in oil and gas discoveries in 1970-1972. However, production from the area cannot possibly begin before 1978, 14 years after significant expenditures commenced. As a final point, there is little governments can do to hasten the timing of discovery. On the other hand, governments' actions can easily create uncertainty with respect to vital factors such as share, markets and prices which could slow the pace of exploration. CONCLUSIONS 1. Canada has significant potential crude oil resources. 2. Potential oil resources will remain undiscovered unless the combination of geologic risk, government share, price, and timely market outlet can be perceived by the explorer to provide a potential reward commensurate with the money at risk. 3. The extremely uneven distribution of oil in the earth is such that a very few explorers will make substantial returns on investment while most will be less fortunate; yet it is the expectation of doing better than average that motivates explorers to risk large sums of money. 4. Canada will require significant crude oil supply additions in the future. This can be effectively realized by a continuation of Canada's competitive enterprise system; however, their timely development will require a clear understanding of the role of the basic factors of price, market, stability of regulations, and share of reward between the public and the investor. It is the purpose of this paper to aid in this clear understanding. REFERENCE 1. An Energy Policy for Canada - Phase I, Vols.l & 2, Information Canada, Ottawa, 1973. CANADA'S POTENTIAL ENERGY RESOURCES

POTENTIAL BARRELS Gil FUEL RESERVES • EQUIVALENT (billions)

Conventional Crude Oil 92 billion bbls. 92 Athabasca Oil Sands & Heavy Oil 331 billion bbls. 33. Natural Gas 765 trillion cu. ft. 126 Coal 120 billion tons 480 TOTAL OIL EQUIVALENT 1,029 billion bbls.

PROVED REMAlNrNG RESERVES PLUS ESIIMflTEO UNOISCOVER6I1 POTENTIAL SOURCE GEOLOGICAL SURVEY OF CftNAOA 197] Fig. i

AMPLE FOSSIL FUELS TO MEET SHARE OF ENERGY MARKET TO YEAR 2050 PROJECTED POTENTIAL BSUIOIfS CANADIAN FOSSIL •US DEMAND FUEL CHI EQUIVALENT FOR ENERGY RESOURCES i.ooo-

800- NUCLEAR AN-D : OIL, 500 HYDRO GAS. POWER, OIL SANDS, / COAL 400

200 FOSSIL FUELS

•INIltmtOHHIMlNIOUMflltOMN AX IMHGV Fill(CT f ID! ,:.Vjfl!!A UI^!U'M*i1 III | VINES AMU niSOURClS OllrtWft 11/1 •PIKSI «*Il V PWIIVl 0 Hl'.tfllNIM, 1*1 US fl^niSt.ilvi HI (I KHINMM Mtsp'M .

Fig. 2 45

ENERGY RESOURCES AND THEIR DEPENDENCE ON PRICE: NATURAL HAS by V.L. HORTE Canadian Arctic Gas Studies Limited, Toronto

I think that most of vou here todav, like myself, would aqree that Canada is most fortunate in having amole potential resources of fossil fuels to meet its energy requirements until such time as these can he sunnlied by other forms of energy. We are more fortunate in this resnect than most industrial nations of the western world. Fortunate, however, onlv if we recognize the challenge of converting potential energy into available energv. We must take the necessary steps to ensure that adequate sunplies of energv are developed and made available in the riqht form, by the time they are needed, and at comoetitive costs. One form of energv we must continue to develop to meet near term needs is natural gas from domestic supplies, if we are to maintain our self- sufficiency in energy. About 85% of Canada's estimated ootential natural gas resources lie in the Arctic and offshore frontier reqions. It is to these potential supplies that Canada must look, by the end of this decade, if gas supply shortages are to be avoided. An initial sten in makinq these frontier gas supplies available for Canadian consumers will be the S5 billion Arctic Gas pipeline. Canada's potential fossil fuel resources -- oil, natural qas and coal -- amount to the equivalent of more than one trillion barrels of crude oil, as shown in Figure 1. The data here are taken from the extensive oolicv study completed earlier this year by the federal Department of Enerqv, Mines and Resources. We have converted the estimate of potential reserves made by the Geological Survey of Canada into equivalent barrels of oil on the basis that six mcf of gas are equal to one barrel of crude oil, and four barrels of crude oi1 are equal to one ton of coal. This potential resource base of one trillion barrels of oil is equivalent to more than three times Canada's estimated demand for fossil fuels during the 80-year period from 1970 to 2050, as inferred from the Enerqv, Mines and Resources' study. (Figure 2.) Certainly, a great portion of this energv potential supply will be available only at prices substantially greater than nresent energv costs. But based on projected trends of world demand/suDply relationships, the orospects for lower-priced alternative energv suoDlies are not encouraqinq. Demand for fossil fuels in Canada is expected, accordinq to the government study, to start declining by about 2020, and will be sharoly reduced by year 2050. By that time, electrical energy could account for 90? 46

TRILLIONS OF CUBIC FEU 120 DISCOVERED 10 AND POTENTIAL ° UNDISCOVERED GAS RESERVES POTENTIAL" OF WESTERN 8D CANADA 60 REMAINING RECOVERABLE NATURAL GAS 40 RESERVES AT DEC 31 72*

20 CUMULATIVE PRODUCTION TO73 Fig. 3 TRILLIONS CUBIC FEET SUPPLY 120-

i 100- i MISLEADING UNDISCOVERED POTENTIAL j COMPARISON 1 80- DEMAND OF CANADIAN TO 1987 GAS SUPPLY & 60- DEMAND REMAINING RECOVERABLE NATURAL GAS FORGANADfAN 40- RESERVES At DEC 31/72

20- CUMUL'ATivi PRODUCTION 1/ PROOUCTI.ON Fig. 4 of total enerqv needs. In turn, electrical enernv is then exoecteH to he qenerated almost entirely from nuclear reactors. It was this analvsis which led the government study to conclude that "Canada has more than enouah enercp/ resources available to rover her own use at least until the vear ^50." n.nd bevond this is the wide range of ootential new forms of enerqv -- nuclear fusion, solar, geothennal, and othei•« -- amon>] which nuclear fusion -Â solar enerqv can he looked unon as virtually unlimited and inexhaustible. We do not need to question the adequacv of our notential enerqv resources. The question we must ask is this: will our enerqv resources be developed and made available at a rate that keens pace witt the qrowth in demand and at a price competitive with world enerqv nrices? I do not intend to explore the supolv/demand outlook for oil, which will be discussed in deoth by others at this conference. However, there is one ooint that our studies at Arctic Pas clearly indicate. Neither in terms of price nor availability, can we exoect that petroleum sunnlies will provide a more attractive or realistic alternative to meeting present or anticipated demand for natural gas. Thus, development of adequate supplies of natural gas is most important if our total future enerqv needs are to he fully satisfied. Fiqure 3 shows that less than one-third of the ootential marketable reserves of natural qas which the êoloqical Survev of Canada estimates for western Canada still remain to be discovered. The êoloqical Survey of Canada study, issued earlier this vear in the qovernment's naner on energy policy, estimated 113 trillion cubic feet of potential reserves to exist in the four provinces of western Canada. Of this estimated notential, approximately 152 had been produced bv this year, and more than 51* represented remaining discovered reserves. I must mention that studies by mv own company indicate that the undiscovered potential qas reserves of western Canada are appreciably greater than that estimated by the Geoloqical Survpv nf Canada. We can conclude from Fiqure 3 that we have discovered and have committed to markets, in large part, the total western Canadian potential. I would add that it is also reasonable to exnact that the remaining notential will be more difficult to find, that the rate of discovery will decline, and the cost of finding will increase. The information shown in Figure 4 is of the tvoe which has led some of the academic economists in Canada to lean to erroneous conclusions as to the adequacy of our natural gas supply. It shows the volume of remaininq Droved plus potential qas reserves in western Canada to be appreciably qreater than the forecast of production demand during the next 15 years. The market studies by Arctic Gas suggest that less than 50 trillion cubic feet of production will be required during the next 15 vears, in order to meet presently authorized export volumes plus growinq domestic demand. However, the limiting factor in supply is not simnlv the volume of reserves, but the rate at which the reserves can be produced to meet specific daily and annual demands. I am sure that most of you are well aware of the fact that as qas is withdrawn from a reservoir, the pressure is reduced; as it reduces, the rate of production declines. Thus, while remaining reserves mav be large, the rate of delivery from those remaininq reserves is lessened and the time period for their recovery lengthened. Some 48

OELIVERABIUTY LIMITATIONS OF GAS PRODUCTION FROM WESTERN CANADA TRILLIONS OF CUBIC FEET 3-

1973 1978 1983 1988 1992

PROJFCTfll VOLUMES ANNUAL WESTERN CANAOA GAS PRODUCTION SOURCE CANADIAN OHCTIC GASJ.1UDY 1IWIUD

Fig. 5

CANADiAN DEMAND FOR NATURAL GAS WILL CONTINUE

OF CUBIC TO GROW FEET

1- AUTHORIZED EXPORTS

1973 1978 1982 1987

SOURC£ CANADIAN AHCTIf. GAS STUDY ilMIIt Fig. 6 49

SUPPLY SHORTAGE CANADA PRODUCTION

2 DEMAND RATE WILL EXCEED FORECAST GAS PRODUCTION 1 - FROM WESTERN CANADA THIS DECADE

1973 1973 1982 1987

SOURCE CANADIAN ARfllC G«S;.TlinV IIMIII Fig. 7

1MUMM WESTEBW SAWADA IS FEET ONLY GAS SUPPLY CANADIAN CONSUMERS

401

WESTERN FROVED REMAINING RECOVERABLE GAS RESERVES AS Of DEC 31/72 PLUS FOIEUtlAl UROISHOVEREO llfSt BVEi SOURCES: PROVED RESERVES . CAMAStlA* ?f THOLtUH «SiOCinTIDN CANADA fOTEBTWL HESEBVES... CEfllOBIUl SURVEY6F U0NSD4 1573 Fig. 8 50

sool TRILLIONS OF CUBIC FRONTIER REGIONS FEET ACCOUNT FOR 85% SQO OF CANADA'S POTENTIAL GAS SUPPLIES 400

200

WESTERN CANADA FRONTIER REGIONS

Fig. 9 51 diagrams will demonstrate this. Figure 5 portrays projected production of western Canada gas reserves during the 20-vear period 1973 to 1992. It is based upon assumptions as to the future rate of gas discovery in this region, and the deliverabilitv limitations on the resulting reserve suoply. It shows production increasing from a rate of nearly 2.6 trillion cubic feet this year to a peak of nearly 3.2 Tcf in 1979. Thereafter the rate declines gradually to a volume of 2.9 Tcf in 1992. I have mentioned that our studies suggest a greater potential gas supply in western Canada than the most recent estimates by the Geological Survey of Canada. This greater reserve potential is reflected in the production curve shown in Figure 5. If the Geological Survey of Canada's estimate of potential reserves were to be used, the rate of production decline would be more raoid than shown here. Projected demand for Canadian gas during the next 15 years is plotted in Figure 6, which shows the volume of exoorts to the United States declir' g as some of the presently authorized exoorts terminate during this period. But domestic demand for natural gas shows a steady growth. Total demand increases from a rate approaching 2.6 trillion cubic feet this year to about 3.6 Tcf in 1987. Figure 7 shows a combination of the projected market demand with the projected rates of gas production from western Canada. It shows that production falls short of meeting requirements within six years — in 1979. This shortfall is not very great in 1979, amounting to 1% of demand. But hv 1907, projected western Canada production is about 15% short of indicated demand. Figure 8 shows that the four provinces of western Canada today comprise virtually the only available qas SUODIV to meet Canadian reguirements and our presently committed export volumes. As previously noted, this represents a presently discovered and remaining potential supply source, based on the Geological Survey of Canada estimates of some 95 trillion cubic feet. Fortunately, we have the frontier regions (Figure 9); and it is here that 85$ of Canada's potential gas resources are locatc-d, again based on the latest Geological Survey of Canada estimates. After allowing for production to date, the remaining indicated potential, based on Geological Survey of Canada estimates, amounts to some 775 trillion cubic feet. Of the frontier regions, the largest potential is indicated for the wide-spread eastcoast offshore area, with about 40^ of the indicated total. The northern mainland and Beaufort region is estimated by the Geological Survey of Canada to contain more than 100 tcf of potential gas reserves. What about prices? If natural gas is to look after its share of the energy market, it must be available at prices competitive with alternative forms of energy. Certainly it will cost more to get gas from our frontier areas than it has cost in the past from western Canada. However, there can be little doubt that costs associated with developing tha remaining and more difficult to find;potential in western Canada will be high. With respect to frontier sources, and in particular Delta gas, we are confident from our cost studies that we will be fully competitive with anticipated prices of alternative forms1 of energy. For example, based on projected world oil prices, we expect t;0i see Ibw-stilphyr content *^el oil selling by 1980 in Toronto at a price equivalent tpabe^toeen|^ and three times the present natural gas city gate price. Moreover, ft seems; highly unlikely tha+ we could develob adequate 52

domestic oil supplies at less than world nrices. When we look at other possible forms of energy -- such as coal gasification, nuclear energy or other new energy sources -- we must conclude that they will play an important role in our longer-term energy needs. But it is most improbable that these could be develoDed in time or on sufficient scale to ne attractive, realistic alternatives for our near term energy needs. Yhe largest supply of discovered reserves which could be available before 1980 to supplement western Canada will likely be those in the Mackenzie Delta-Beaufort area. In September, Arctic Gas reported estimates bv the consulting firms of <1.C. Sproule and Associates, and OeGolver and MacNauqhton. These firms independently estimated the potential reserves of the Mackenzie Delta, including the shallow water areas of the Beaufort Sea, to be aDoroximately 55 trillion cubic feet. They also concluded that further substantial but longer-term potential reserves exist in the Beaufort Sea area bevond the shallow water area. Of the 55 trillion cubic feet of potential reserves, the studies showed that aoproximatelv seven trillion cubic feet of gas can be exoected to be derived from fields discovered at that time. Considering the few wells drilled in the areas to date, the results are most encouraging. Our consultants estimated chat at the current rate of exploration drilling, substantial additional reserves will be established prior to the completion of the proposed Arctic Gas DiDeline. '!" mid-1973, the 27 firms oarticipating in Arctic Gas had spent in the order of $40 million to examine in detail the engineering, economic, environmental and northern reaional sociological aspects of the proposed piDeline. The pipeline will comprise more than 1,900 miles of 48-inch diameter pipeline, and more than 650 miles of 42-inch diameter oipeline. Of this, in the order of 200 miles would be in Alaska and the remainder in Canada. The proposed route extends from the gas suoplv areas, south through the Mackenzie Valley, and into Alberta to a noint northwest of Calgary at Caroline. Here it splits, with one 42-inch diameter leg extending southwest and the other 42-inch diameter leg extending southeast. Northern gas for Canadian markets east of Alberta will be picked un from Arctic Gas pipeline on the Alberta/Saskatchewan border near Empress bv TransCanada PiDeLines. In turn, TransCanada would move this gas across Saskatchewan, Manitoba, Ontario and Quebec. This would assure sustained construction exoansion on the TransCanada pipeline across the orairie provinces and Alberta for a long period. Even more importantly, it would ensure the continued use of existing pipeline facilities as gas suonlies from western Canada start to decline. In the far north, several alternative routes are still under consideration. They include two principal ontions from Prudhoe Bay across Alaska and the northern Yukon. One route lies east from Prudhoe Bay along the coastal plain, then south un the Mackenzie River Vallev. This route would cross the Alaska Wildlife Range. The major alternative follows the Alaska 'utility corridor" to skirt the Wildlife Range by crossing the Brooks Mountains in Alaska and the Richardson Mountains in the Yukon. This coastal route Is shorter, appreciably less costly, would traverse a greater area of potential gas supply, and, we are advised bv our consultants, would involve less ris' of environmental impact. 53

With installation of full compressor horsepower, the niDeline would be able to deliver in excess of four billion cubic feet of gas Der dav. Additional capacity can be installed as required, bv means of incremental looning with more large-diameter pipe. Throuqhout the areas of nermafrost, roughly north of 60 degrees latitude, the gas will be refrigerated at each compressor station to a temperature of about 25 degrees Fahrenheit, so that it will be close to the soil temoerature, and below freezing. This chilled gas concept will allow the pipeline to be fullv-buried along the entire length, and avoids the risk of any permanent damage to high ice-content permafrost. The right-of-way and compressor station sites will occuoy less than 40 sguare miles in the Yukon and Northwest Terriotries, out of an area in excess of 1.5 million sguare miles. Allowing for the regulators procedures, plus assembly and delivery of materials, it is unlikely that construction work could start prior to the winter of 1976-77. With careful olanning. it may be possible to build the northern end of the svstem as far as the Mackenzie Delta during two winter seasons, with the extension to the Alaskan North Slope during the following winter. This means that gas might start flowing from the Delta by nnd-1978, and from Alaska bv mid-1979, assuminn that there are no delays. Excessive delay could be detrimental to Canadian interests, because Canadians are likely to face shortages of natural gas by the end of this decade unless northern supplies are available. Yet Canadian demand, by itself, is not sufficient to pay the cost of a $5 billion pipeline. In order to provide northern gas to Canadian consumers bv the time that it will be needed and at the least possible cost, the pipeline must transport both Alaskan North Slope and Mackenzie Delta gas to both Canadian and U.S. consumers. As presently envisioned, about half of the design capacity of the pineline would be provided by gas from the Alaskan North Slope, and half from the Mackenzie Delta. To achieve maximum transportation economy, the pipeline nronosed bv Arctic Gas would reguire, within a very few years of start-UD, a market outlet i-\ e: :ess of four billion cubic feet per dav. This is more than Dresent total Canadian gas demand, and nearly 20 times the current annual demand growth. The possible loss of Alaskan gas is a real threat to the Arctic Droject. An extensive feasibility study of an alternative transportation route for the North Slope gas is already well underway bv Fl Paso Natural Company. The proposal envisions a pipeline from Prudhoe Bav to Alaska's Pacific coast where the gas would be liquefied for tanker shipment to California. The result of certification of that project would almost certainly be to delay the availability of Mackenzie Delta gas well beyond the time that will be reguired to meet the needs of Canadian consumers, and in our opinion could well prejudice development in the Delta area for many years. Arctic Has does not believe that the El Paso Project is the most economic or the most advantageous means for the United States to gain access to its North Slope gas reserves, But if the United Statas were to face lengthy delay in gaining access to its Alaskan gas by means of a pipeline across Canada, or were concerned about its futare security of SUDOIV, it could

p- 54

well turn to a trans-Alaskan delivery route We in Arctic 'iris do not believe that this will take ;>lace. because Canada and the U.S. in that event would both be losers. I have -aid that Canada is most fortunate in its uotential supplies of energy. Vie should not consider the challenges of develc;>inq this potential as a series of problems. They are really opportunities. I am confident that as a nation, we will seize these opportunities to maintain and enhance the national interest. 55

ALBERTA'S OIL SANDS IN THE ENERGY SUPPLY PICTURE by G.W. GOVIER* Energy Resources Conservation Board, Calgary

INTRODUCTION This paper describes the Alberta oil sands, discusses development work done and in progress, and makes some broad projections of how developments in the oil sands may occur over the next fifteen years. Even with some increase in conventional crude oil discoveries and with further gains through new and expanded recovery operations, the growth in Alberta's initial recoverable reserves of conventional crude oil is expected to be only some 200 to 300 million barrels per year over the next decade. With production expected to be in excess of 500 million barrels per year, at least in the early years, it seems inevitable that Alberta's remaining recoverable reserves of conventional crude oil will continue to decline from some 7 billion barrels today to about 3 billion barrels in 1985. Alberta's conventional crude oil production capacity will likely peak in the next few years at some 1.8 to 2.0 million barrels per day and then decline to some 1.2 million barrels per day by 1985. There is thus a clear need for the development of additional production capacity if Alberta is to maintain its position as a major oil production Province, and the present relation between Canadian crude oil production and consumption is to be preserved. Fortunately, Alberta does have the extensive oil sands deposits from which to provide supplementary production.

LOCATION AND RESERVES OF OIL SANDS Figure 1 shows the location and areal extent of the principal deposits of oil sands which extend over some 19,000 square miles of Alberta. The principal deposits are those of Athabasca, Cold Lake and Wabasca in north-eastern Alberta anrf Peace River in north-western Alberta. The Athabasca deposit is found entirely within the Wabiskaw- McMurray unit under an overburden of muskeg, glacial deposits and cretaceous sediments ranging from zero to 2,000 feet in thickness. The deposit has been extensively drilled and in a broad sense may be considered reasonably well delineated. The areal extent of the deposit is indicated in Figure 2. The deposit covers 5 3/4 million acres, about 1/2 million of which is overlain by 150 feet or less of overburden. This latter area, crosshatched in Figure 2, is the area suitable for surface mining. Figures 3 and 3A are enlargements of the surface mineable area and show the distribution of core holes and the major leaseholders. Coring, * Paper presented by G.A. Warne. 56

ATHABASCA OIL SANDS PEACE RIVER OIL SANDS PEACE*. RIVER

WABASCA OIL SANDS COLD LAKE OIL SANDj

O EDMONTON

O CALGARY

FIGURE 1- LOCATION AND EXTENT OF MAJOR OIL SANDS DEPOSITS OF ALBERTA 57

R24 R20 R 4 WdM

T78

FIGURE 2 ATHABASCA OIL SANDS DEPOSIT AND SURFACE MINEABLE AREA 58

FIGURE 3° SURFACE MINEABLE AREA OF ATHABASCA DEPOSIT SHOWING CORE HOLE LOCATION 59

T.»9

AMERADA 90 I / HOME 30

T90

R.I3 FIGURE 3A SHOWING LEASE OUTLINES AND OWNERSHIP 60

logging and surface mining operations indicate much variability in the thickness and grade of the deposit and the erratic presence of lenses of dense hard material. Figure 4, which is a cress-section through parts cf the Great Canadian and the neighbouring Syncrude leases, illustrates the variability in the thickness and the quality of the sand. The Board made a detailed appraisal of the in-place reserves of crude bitumen in the Athabasca deposit in 1963. This was based upon core and log data obtained from over 1,600 wells. Some 1,200 additional wells have been drilled and logged or cored since 1963. These provide important detail in particular leases, especially in the areas of low overburden, but would not likely have a major effect upon the estimate of the overall in-place reserves. The Board's estimates of the in-place reserves of crude bitumen in the Athabasca deposit, unchanged from 1963, are 74 billion barrels in the 0-150 feet overburden range and 552 billion barrels in the 150 - 2,000 feet overburden range for a total of 626 billion barrels. These figures are based upon a 2 weight per cent saturation cut off. They represent the proved in-place reserves of crude bitumen. Over the past five years some 72 million barrels of synthetic crude oil has been produced by Great Canadian through mining and surface extraction operations. The Board believes that recovery of crude bitumen by surface mining methods to an overburden depth of about 150 feet, and for overburden to pay ratios of one or less, may now be considered proved. The limiting overburden thickness and the overburden to pay ratio reflect current prices, recovery economics and technology and what may reasonably be anticipated in the near future. Early this year the Board reviewed its 1963 study of the in- place reserves of the Athabasca deposit and, for the deposit in the 0-150 foot overburden range, made an appraisal of the quantity of crude bitumen which could be considered as proved recoverable and the amount of synthetic crude oil which it would yield. In this appraisal the Board assumed that only those sands containing 5 or more weight per cent crude bitumen, under less than 150 feet of overburden, and with an overburden to pay ratio of less than one, to be in the proved recoverable class. Appli- cation of these criteria and assuming a 90 per cent mining recovery leads to a recoverable reserve of 38 billion barrels of crude bitumen -- the amount now considered proved by mining methods. Great Canadian is now realizing a separation of crude bitumen and a conversion tr synthetic crude oil of 69 volume per cent; Syncrude anticipates a separation and conversion of 75 volume per cent. Using a conservative 70 volume per cent separation and conversion the 38 billion barrels of proved recoverable crude bitumen will yield 26,5 billion barrel: of synthetic crude oil. While the Board now considers only 38 billion barrels of the 552 billion barrels of in-place reserves of crude bitumen in the Athabasca deposit to be in the category proved by minir.g techniques, the Board is 61 optimistic that in situ methods will be developed to permit the recovery of a substantial part of the bitumen in the deep deposits. Even a 20 per cent bitumen recovery would lead to 110 billion barrels of crude bitumen which at a 70 per cent conversion would yield nearly 80 billion barrels of synthetic crude oil. The Board has made similar appraisals of the Cold I ke, Peace River and Wabasca deposits. These deposits contain in-place reserves of crude bitumen of 164 billion, 50 billion and 54 billion barrels respectively. At a 20 per cent bitumen recovery and a 70 per cent conversion the Cold Lake deposit would producf 20 bi"11 ion barrels and each of the other two deposits 7 billion barrels of synthetic crude oil, none of which may yet be classed as proved recoverable. A summary of the proved reserves of crude bitumen and synthetic crude oil is given in Figure 5. The figures which I have so far quoted are what the Board now considers to be the proved in-place reserves of bitumen, the proved recoverable reserves of bitumen and the proved recoverable reserves of synthetic crude oil. The ultimate reserves, i.e. the reserves that may ultimately be expected to be proved, may only be broadly estimated. The Board's judgment is that the ultimate in-place reserves of crude bitumen, at a 2 or 3 per cent cut off will be about 1,000 billion barrels; the ultimate recoverable reserves of crude bitumen at an average recovery of 33 per cent will be 330 billion barrels and the ultimate reserves of synthetic crude oil at 75 per cent volume conversion will be about 250 billion barrels.

PROGRESS IN DEVELOPMENT Experimental Projects Over the past several years some 20 experimental field tests or pilot schemes have been conducted in the oil sands deposits — mostly by major oil companies. At present two major tests and a number of minor tests are underway and one major test by Shell at Peace River which was suspended for a time is being resumed on an expanded basis. Amoco Canada Petroleum Company has been conducting field tests of its in situ recovery process since the late 1950's. Already having Invested about 9 million dollars in research on oil sands recovery methods, the company has announced plans to spend approximately 13 million dollars on further research into in situ recovery methods. Amoco is currently expanding its field program to obtain further design data relating to the application of underground combustion followed by waterflcoding. Imperial Oil Limited is continuing work it started at Cold Lake in 1964 on in situ recovery by steam injection. Imperial has drilled a further 23 shallow wells under the present program and is producing 1,500 barrels of crude bitumen per day. The company, in an application now before the Board, has applied for approval to add further facilities to boost the pilot plant rate to 4,000 barrels per day and to continue it for av

II-2S-N-K !6-i8-9Z-IO 10-20-92-10 I1-I4-92-I0IM

HUH 4 CIISI SKIM in

IEOENP FEED BITUMEN SATUtATIOH >IOV. PLANT FEED 1ITUMEN SATURATION < 'OV. KJECT MATERIA1 DEPOSIT OVERBURDEN AREAL CRUDE RECOVERABLE REMAINING RECOVERABLE DEPTH EXTENT BITUMEN CRUDE SYNTHETIC INTERVAL IN PLACE BITUMEN CRUDE OIL {FEET) (M ACRES) (MMSTB) (MMSTB) (MMSTB)

ATHABASCA 0-150 490 74,000 38,000 26,500 150-2000 5,260 551,900

COLD LAKE A 1000-2000 1,800 117,900 B 1000-2000 650 32,700 C 1000-2000 710 13,500

BUFFALO HEAD HiLLS 500-2500 159 900

PEACE RIVER 1000-2500 1,180 50,400

WABASCA A 250-2000 764 30,400

WABA5CA B 1OOO-2.5OO 1,000 23,400

TOTALS 12,013 895,100 38,000 26,500

FIGURE 5 - PROVED RESERVES OF CRUDE BITUMEN AND SYNTHETIC CRUDE OIL IN ALBERTA

oi 64

a further five years. Imperial has indicated that it is hopeful that in 5 or 10 years at the end of the test period it will have determined if a commercial operation using the technique is feasible in the Cold Lake deposit. The Shell in situ test in the Peace River oil sands deposit also involves the injection of steam and is being carried out on a 175,000 acre lease. If the results of the program warrant it, the company plans to undertake an expanded program involving 40 to 50 injection and production wells over a period of three years at a cost of some 15 million dollars. Should this program also prove successful, Shell would seek approval late in this decade for a commercial scheme of some 100,000 barrels per day capacity and similar in cost to an Athabasca surface mining scheme.

Commercial Development The first commercial plant in the oil sands was built by Great Canadian Oil Sands Limited, a company controlled by Sun Oil Company. It began production in 1967 and has gradually built up its production rate. In 1972 the rate averaged 51,000 barrels per day compared with its design capacity of 45,000 barrels per day and in 1973, despite a scheduled shut down for a major plant overhaul, this rate appears likely to be maintained. Great Canadian has applied to the Board for approval to increase the production rate to 65,000 barrels per day and that application is presently being considered. The process em\. jytd by Great Canadian involves removal of some 70 feet of overburden, mining, separation of the sand and bitumen, clean- up of the bitumen, and upgrading of it to sweet synthetic crude of 34° AP gravity. Giant bucket wheel excavators now supplemented by trucks and front-end loaders, are used to strip overburden and to mine the oil sands. Many problems were encountered in the early operation of the project but most of these problems have now been overcome. Great Canadian is mining some 80 per cent of the in-place bitumen in its lease; it separates 90 per cent of the crude bitumen contained in the mined sand; and effects a 65 weight or 78 volume per cent conversion of the recovered bitumen to synthetic crude oil. The overall result is a recovery, in the form of synthetic crude oil, of about 47 weight or 56 volume per cent of the bitumen in place. The Board considers these recoveries to be good for a first commercial operation. The synthetic crude oil from the project is of excellent quality and in high demand as a refinery feedstock. The price at Edmonton is now 4.20 dollars per barrel equivalent to about 3.95 dollars per barrel at the plant site. The capital cost of the Great Canadian project, including all on-site facilities but exclusive of road, bridge, pipe line and townsite development in Fort McMurray, was some 260 million dollars. The total represents a unit capital cost of $5,800 per daily barrel of original rated capacity of 45,000 barrels per day. The unit cost will decrease to 65 some $4,500 per daily barrel with the probable raising of the throughput to 65,000 barrels per day. The economics of the Great Canadian plant are still not good but with increasing crude oil prices and the probable raising of the production rate to the 65,000 barrels per day level the outlook for the plant is favourable. Syncrude Canada Ltd. is the operator for the team of Atlantic Richfield Canada Ltd., Imperial Oil Limited, Canada-Cities Service Ltd., and Gulf Oil Canada Ltd, and has approval for a second commercial oil sands development of 125,000 barrels per day capacity. This project is scheduled to commence production in late 1977. The production rate would increase gradually to 105,000 barrels per day of synthetic crude oil in 1980 and to 125,000 barrels per day by 1984. The project has been developed through a program of research work performed over some ten years and will also benefit from the experience of Great Canadian Oil Sands. Research and development expenditures have totalled about 30 million dollars. Syncrude plans to use large draglines rather than bucket wheel excavators for the overburden removal and mining operations provided the results of tests now in progress are satisfactory, but in other respects the operation will be generally similar to that of Great Canadian. A significant difference in the upgrading process wil7 be the use by Syncrude of fluid coking rather than delayed coking used by Great Canadian. Syncrude expects to mine about 87 per cent of the in-place bitumen in its mining area; to separate 91 per cent of the crude bitumen contained in the mined sand and to convert 71 weight or 82 volume per cent of the recovered bitumen to synthetic crude oil. The overall recovery of synthetic crude oil is expected to be 56 weight or 65 volume per cent of the in-place bitumen. If these recoveries are achieved they will represent a significant improvement over those of the first plant. Earlier thi^ year Syncrude:applied to the Board for an amendment to the approval which it holds to permit certain technical changes in the process and fora delay in the authorized construction schedule. The Board's decision on this application was released on September 10, 1973, and approved by 1;he Alberta Government September 19. Syncrude and (the Government pf Alberta have had extensive discussions and have recently largely reached agreement concerning royaltyc public participation, environmental controls, use of Wlbbrta materials, skilled labour and["professional services. Meanwhile, Syncrude has been proceeding towards the;start of major construction and a considerable number of senior staff have been hired for the program. Cost estimates for the program indicate";the capital cost including all on-site facilities but exclusive of road, pipe line and townsite development will be close to 900 million dollars. Even at the full capacity of 125,000 barrels per day this represents a unit capital cost of some $7,000 per daily barrel. 66

Considering inflation, this is quite comparable to the Great Canadian figure. Shell Canada Limited and Shell Explorer Limited have submitted an application to the Board for a third commercial mining project. The hearing of this application began October 9 and will resume, following adjournment, on November 1. Shell proposes the production of 100,000 barrels per day of synthetic crude oil commencing in 1980 and reaching full scale in 1982. Shell would use drag lines for primary excavation, front-end loaders for rehandling and a rail system for haulage. It would follow Great Canadian and Syncrude in its use of the hot water extraction and froth separation processes. Shell proposes to upgrade the recovered bitumen by hydrotreating and hydrocracking. Present estimates indicate a capital cost of the Shell project of the same order as the Syncrude project. While I have commented favourably on the recoveries being obtained by Great Canadian and expected by Syncrude, I should not stop there. There are several respects in which future plants, benefiting from the experience of their predecessors and from new technology, should do better. I would suggest the following objectives: 1. The mining method should permit the mining of not less than 90 per cent of the oil sand containing over 5-6 per cent crude bitumen within the lease. 2. The extraction system should result in the recovery of not less than 95 per cent of the crude bitumen contained in the recovered sand. 3. The upgrading process should result in not less than a 75 weight per cent conversion of the recovered crude bitumen to synthetic crude oil. 4. The process should be self-sufficient in energy -- no natural gas should be required and electrical power interconnection should be for emergency purposes only. 5. Production of coke, char or heavy fuel oil in excess of site fuel requirements should be eliminated. 6. Sulphur recoveries from all sources should be in the range indicated in the Board's Sulphur Recovery Guidelines for Gas Processing Plants.

OUTLOOK FOR THE FUTURE Let me turf, low to trv_ ..tee of synthetic crude oil in the future. It is recognised that filoerta's conventional industry is approaching its capacity. Canada has good prospects for new conventional crude oil production, especially in the Mackenzie Delta, the Arctic Islands and off 67 the East Coast, and in time these will contribute to Canada's supply. Meanwhile, Canadian crude oil requirements continue to grow at 4 to 5 per cent per year and the gap between United States requirements and its indigenous supplies widens at an alarming rate. Under these circumstances the amount and timing of the addition which the oil sands could make to Alberta's productive capacity is of great importance. The presently proved reserves are adequate to support 20 to 30 plants of 100 - 150,000 barrels per day capacity and producing 3 million barrels per day. Up to this rate reserves would not be limiting and no new technology would be required. What are limiting, however, are availability of capital, equipment manufacturing facilities, design and other professional services, construction labour and operating personnel. The magnitude of these factors is indicated by the approximate requirements for a 100,000 barrel per day plant. Total Capital 800 million dollars Specialized Equipment 200 million dollars Design and Professional Services 800 man-years Construction Labour 5,000 man-years Operating Personnel 1,500 men Furthermore, substantial lead time from project conception to start of production is necessary — five or six years. Bearing in mind these very real limitations, my own judgment is that synthetic crude oil production will not much exceed 200,000 barrels per day in 1980 and that it could reach 800,000 barrels per day in 1985. Some conception of the manner in which additional synthetic crude oil production will be developed is given in Figure 6. The Board believes that perhaps four mining projects, including the Great Canadian, Syncrude and Shell schemes already announced, will be undertaken before the first in situ recovery operation. However, probably in the early 1980's a couple of in situ projects will be undertaken on a commercial basis. In all likelihood these will develop from the work underway and planned by Shell, Imperial and Amoco, the present leaders in development of in situ recovery techniques for the oil sands. If the two in situ operations, not. now proved, did not develop, the probable maximum production by 19S5 would be in the order of 500,000 barrels per day, or perhaps a further mining project would raise the total to about 600,000 barrels per day. This brings us to Figure 7 and the outlook for Alberta's total liquid hydrocarbon production. The forecast of conventional crude oil production is based upon an intermediate rate of growth in conventional reserves. The figure shows conventional crude oil peaking at about 1.9 million barrels per day through 1977 to 1979, conventional crude oil plus natural gas liquids peaking at 2.3 million barrels per d?v4 with synthetic crude oil raising the p<2ak to 2.4 million barrels per day. The natural gas liquids, CO

1000

1967 '71 73 '75 '77 79 '81 '83 1985 YEAR FIGURE 6-ALBERTA SYNTHETIC CRUDE OIL PRODUCTION 2500

SYNTHETIC CRUDE OIL-

LU Q- 2000 r-r if * LU DC NATURAL GAS LIQUIDS CD //_/ o 1500

O 1000 CONVENTIONAL CRUDE OIL z" o H- 3 500 O O HISTORICAL FORECAST

60 65 70 75 80 85 YEAR FIGURE 7-ALBERTA LIQUID HYDROCARBONS PRODUCTION

en 70

shown on this figure as nearly constant in the range of 370,000 to 390,000 barrels per day, include some 180,000 - 190,000 barrels per day of propane and butane with the remainder (about equivalent) being pentanes plus. Synthetic crude oil production will slow the decline in total production over the period 1979 to 1982 and afterwards will reverse the decline to return productive capacity to 2.3 million barrels per day by 1985. Even without the two in situ developments, Alberta's total liquid hydrocarbon production will be maintained above 2 million barrels per day. We may conclude that synthetic crude oil is going to be important in the future of Alberta, Canada and the United States. It will be needed to offset the inevitable decline in our conventional production and to maintain and increase Alberta's total productive capacity. The extent of reserves proved to exist and proved to be recoverable will not limit development of mining projects. The prospects for commercial development of in situ projects are good although recovery by such means is not yet proved. The large requirements of money, equipment and manpower and the long lead time for oil sands projects makes early planning essential. It is reassuring to know that such planning is occurring both in industry and Government. 71

RELATIONSHIP BETWEEN COAL PRICE LEVELS AND QUANTITY OF ECONOMICALLY RECOVERABLE COAL IN CANADA

G. D. COATES Luscar Ltd., Edmonton, Alberta

If the contribution which Canada's large coal resource can make is to be properly taken into account in the determination of new energy policies, it is important to try to establish the relationship between coal prices and the magnitude of the nation's economically recoverable coal reserves. Unfortunately, so little of the necessary data is available that any conclusions can as yet be little more than tentative and speculative, but the matter is of sufficient importance at this time to warrant an attempt to establish the relationship. This paper constitutes such an attempt.

A definitive assessment would require reliable information about each of the following:

1. What is the nation's total coal resource? How much coal (by rank) exists in Canada; how does it occur and where?

2. How much of the total resource is mineable? To what extent will the mineable portion be increased by future technological improvements or decreased by future environmental restrictions?

3. What prices are necessary for recovery on an economic basis?

These questions are considered briefly below.

1. The Total Coal Resource. For these purposes, there is a need for not only reliable data, as to total in-place tonnages of each rank of coal but also information about the nature of the deposits, including:

- quality of the in-place coal - seam thickness and dip - seam partings - depth below surface - nature of overlying strata (i.e. composition of overburden, or roof conditions).

Such detail is at present unavailable, except in the case of some specific properties which account for only a small fraction of the 72

total resource. While estimates exist by rank of coal and province, these are based largely on data which are meager compared to the data required for mine planning and cost estimating, and include so little information regarding the nature of the deposits that economic assessment can be little more than speculative.

2. Mining Technology and Environmental Restraints. Technological considerations include the following:

(i) How much of the coal can be mined by surface methods? (ii) How much of the balance is recoverable by more costly underground mining methods, and what is the recoverable percentage? (iii) What will be the impact of further development of mining technology in future? As mining technology improves, reserves will move from the uneconomic to the economic category.

Without comprehensive information about the nature of the coal deposits no more than rough assumptions can be made about mineability; predictions about future mining technology can only be speculative.

Environmental and land-use restrictions have already placed certain deposits beyond reach for mining purposes; at this time, no one can predict with any certainty what the future balance will be between environmental considerations and economic benefits. Rightly or wrongly, it seems probable that the recovery of some known deposits of coal will not be permitted in future for environmental and conservation reasons.

3. Mining Economics. Full consideration of this factor would encompass all the costs of delivering to the ultimate consumer the energy derived from the coal, including:

(i) the cost of mining unprepared or run-of-mine coal; (ii) the cost of preparing the coal (i.e. crushing, screening and, where appropriate, cleaning it); (iii) the cost of transporting the coal or the energy derived from it.

Coal preparation can add heavily to costs, and in the Canadian context, the cost of transportation frequently exceeds the cost of mining. This paper, however, will not consider mere than the price of run-of- mine (i prepared) coal FOB mine.

The adverse effect which recent mine health and safety laws in the United States have had on underground productivity and on capital investment and hence on costs, and the increasing cost of reclamation in the course of surface mining make it clear that future trends along these lines should be taken into account in attempting to assess the future economics of coal mining, but that too is beyond the scope of this paper. 73

ESTIMATES OF THE MAGNITUDE OF THE CANADIAN COAL RESOURCE

In contrast to the production of only a few million tons of coal per year from Canadian mines at present (20 million in 1972), the nation's coal reserves are measured in the billions of tons. The most recent estimate1 by the Geological Survey of Canada (issued in 1970) indicated a total in-place coal resource in the three western provinces amounting to 118 billion tons with the eastern provinces^ contributing another 1.5 billion tons. Alberta's Energy Resources Conservation Board recently published a study^which estimated proved recoverable coal reserves remaining in that province °.Ione to be 8.7 billion tons. The following table summarizes the results of the two studies:

ERCB GSC Estimate of Geological Reserves proved remaining recoverable reserves in Measured Indicated Inferred Total Alberta Millions of Short Tons

Low & medium volatile bituminous B.C. 6,943 10,775 40,480 58,198 n.a. Alberta 982 19,620 7,367 27,969 3,220

High volatile bituminous •DR . OL*. 46 100 173 319 n.a. 6,278 3,044 9,322 226 Alberta

SubbAlbert ituminoua s 1,222 6,197 2,530 9,949 5,341

Lignite B.C. 340 300 300 940 n.a. Saskatchewan 292 7,024 4,698 12,014 n.a.

Totals B.C. 7,329 11,175 40,953 59,457 n.a. Alberta 2,204 32,095 12,940 47,240 8,787 Saskatchewan 292 7,024 4,698 12,014 n.a.

Western Provinces 9,824 50^296 58,591 118,711 n.a. 74

The fundamental difference between these two estimates should be emphasized. The GSC estimate is of the total resource, i.e. in-place geological reserves. The ERCB, on the other hand, has endeavoured to take a further step and estimate the proved recoverable tonnages remaining within the province. Neither presentation, however, provides the data needed to rpply more than rudimentary economic parameters.

It is also important to be aware of the exclusions from the GSC figures; these include:

(a) coal below 1,000 feet of cover in the plains region and below 2,500 feet in the mountains and foothills; the tonnages so excluded are unquestionably enormous, but have not been taken into consideration because Gf doubtful mir.-J. ility with present technology; with rese ^ ih it can be expected that such coal will increasingly become recoverable, but presumably at great cost by today's standards;

(b) seams less than 5 feet thick; in suitable circumstances, thinner seams than this can be economically mined; (c) known ,,oal deposits (mainly subbituminous and lignitin; in the Arctic:

(d) deposits such as G'rcundhog in B.C. which have until now been regarded as remote and of doubtful recoverability.

: ires e>-jude:

^a) deposits below 500 feet in the plains and below 2,000 feet in the mountains and foothills;

v!\ recovery, by surface mining methods, of seams more than 180 fet." below the surface;

'') reserves considered unrecoverable under current technology and present or anticipated future economic conditions (although 'future economic conditions' are undefined);

(d) for surface mining, deposits for which the ratio of overburden to coal exceeds 10:1 in the mountains and foothills and 15:1 in the plains;

(e) proved reserves contained in seams less than 4.5 feet thick. 75

Neither of the two studies can be regarded as the last word on the subject of coal reserves. Exploratory drilling continues and can be expected to result in significant revisions to the estimates; and the underlying parameters will need to be updated from time to time.

ECONOMIC FACTORS

In the absence of data which would permit a more detailed economic analysis, only the following six 'mining categories' are considered for purposes of this paper; the indicated prices assume:

- 1973 cost and price levels (for wages, materials and supplies, equipment, royalties, etc.); - run-of-mine coal, unprepared (except as noted), FOB mine; - production from relatively large, efficient mines operating consistently at close to rated capacity (e.g. in the case of surface operations, mines producing at least 1.0 million tons per year).

Mining Category I: surface mining of flat-lying seams on the plains to depths of, say, 120 *"?et and at a maximum ratio not exceeding about 15:1 (cubic yards of overburden to tons of recovered coal). Most of such coal should be economically recoverable at prices not exceeding 25c per million BTU.

Mining Category II: surface miring of flat-lying seams to depths in excess of 120 feet. This might involve bucket-wheel excavators where overburden conditions permit, or draglines with longer booms than those generally employed in the coal mining industry today, or pairs of draglines operating in tandem (with considerable costly rehandle of overburden). Required prices would generally be in excess of 25c per million BTU - say in the range of 25c to 35c per million BTU.

Mining Category III: surface mining of irregular and distorted seams in the foothills and mountains, by dragline or shovel/truck methods. Required prices would have to range even higher than for Cate~r"ry II.

Mining Category IV: underground mining, by conventional mining methods, of flat-lying seams at depths of less than 1,000 feet. The following table suggests that this would require prices not less than 45c per million BTU: 76

$/Ton (a) Labour at an average rate of $5.25/hr. including benefits: productivity of 15 tons per man shift 2.80 (b) Supplies & Power: $1.93 per ton (1970 estimate by NPC - see ref. 4) plus 25% subsequent escalation 2.41 (c) Taxes, insurance, royalties, lease rentals, administration, selling expenses, etc. .70 (d) ownership costs (depreciation of investment in both original and replacement facilities, depletion, interest and return on investment) 3.00 $ 8.91

Equivalent c/MM BTU Coal @ 10,000 BTU/lb. 45c Coal @ 8,000 BTU/lb. 55c Mining Category V: underground mining of flat-lying seams to depths in excess of 1,000 feet; until the mining technology is developed, the cost of recovery is unknown. Mining Category VI: underground mining in the foothills and mountains by conventional mining methods, at costs which vary over a wide range depending upon the conditions involved. POSSIBLE ECONOMIC RESERVES: A SPECULATIVE ASSESSMENT The following is offered as no more than a speculative assessment of the order of magnitude of recoverable coal reserves which may ultimately be identified in the major coal areas of Canada. It is based on an examination of published data concerning coal reserves, interpreted in the light of the findings of a corporate exploration programme over the past several years and detailed economic evaluation of a number of specific properties in the bituminous (both coking and non-coking), subbituminous and lignite fields of Western Canada. Nothing more precise than this seems warranted on the basis of the very limited available data about Canada's coal resource in general, and in view of the uncertainties associated with attempting to predict future technological and environmental factors.

1. Subbituminous Coal of Alberta Plains (a) Typical analysis of run-of-mine coal, as delivered: 7,200 to 8,500 BTU/lb. at 20% to 26% moisture and 6% Co 20% ash. 77

(b) Mining Category I (Surface Mining to i20 ft.): tonnages on the order of 4.0 billion tons may ultimately be proved. (c) Mining Category II (Surface Mining below 120 ft.): a further 4.0 billion tons should ultimately be found at this greater mining depth. (d) Mining Category IV (Conventional Underground Mining to 1,000 ft.): ultimate recoverable reserves in this category should exceed the indicated tonnages of surface-mineable coal. (e) Mining Category V (Underground Mining below 1,000 ft.): vast tonnages can be expected to occur below 1,000 feet of cover; recovery must, however, await the development of new mining techniques and there will not be much incentive to tackle this problem while such large tonnages remain which can be more readily recovered at a fraction of the cost of deep mining. Possible mining techniques include in-situ gasification.

2. Lignite of Southern Saskatchewan (a) Typical analysis of run-of-mine lignite as delivered: 5,800 to 7,400 BTU/lb. at 35% moisture and 5% to 7% ash. (b) Mining Category I (Surface Mining to 120 ft.): recoverable tonnages on the order of perhaps 2.0 billion tons may ultimately be proved. (c) Mining Category II (Surface Mining below 120 ft.): additional tonnages should ultimately be recovered below 120 feet, say on the order of 0.5 billion tons. (d) There are no prospects for underground mining of Saskatchewan lignite.

3. Non-Coking Bituminous Coal of the Alberta Foothills (a) Typical analysis of delivered coal: 10,000 to 13,000 BTU/lb. at 4% Jto 8% moisture and 10% to 20% ash. (b) Mining Category III (Surface Mining in Mountains and Foothills): it should ultimately be possible to identify perhaps 1.0 billion tons of such reserves. (c) Mining Category VI (Underground Mining in Mountains and Foothills): the potential recoverable reserves in this category should exceed the possible surface-mineable reserves. It is conceivable that recoverable tonnages on the order of, say, 3.0 billten tons may ultimately be identified.

4. Bituminous Coking Coal of Alberta and B.C. (Clean Coal) The existing coking-coal mine operators (both surface and underground mines) have contracts for the future delivery of approximately 125 million clean tons at prices ranging between about $11.00 and $14.00 per clean short ten FOB mine. It should not be expected that this total tonnage will be increased without higher average prices to 78

compensate for the greater costs which will be incurred in mining increasingly difficult deposits. If the present average price were to double, it is conceivable that on the order of 2.0 billion tons could be identified as economically recoverable by fairly conventional mining methods. Additional tonnages would become marketable at still higher mining costs and prices. This does not allow for the extensive deposits known to exist in steeply- dipping formations which may ultimately prove recoverable by hydraulic underground mining methods.

Other Coal Deposits in Canada

A more complete listing of Canadian coal deposits which are or may in future become economically recoverable would include the following:

(a) Bituminous coal deposits of Nova Scotia; the most recent estimate- indicates the following in-place geological reserves:

million short tons - measured 126 - indicated 466 - inferred 684

Nova Scotia mines accounted in 1972 for less than 1.5 million tons or about 7% of total Canadian production. However, the fact that the Crown corporation which accounts for most of this production reports mining losses in excess of $20.00 per ton casts doubt on the economic viability of recovering these deposits.

(b) Bituminous coal of New Brunswick: measured coal reserves are estimated2 to be only 10 million tons (no indicated or inferred reserves).

(d) Lignite deposit at Hat Creek, B.C.: approximately 600 million tons are thought to be recoverable.

(e) Lignite deposit at Onakawana, Ontario; approximately 240 million tons.2

CONCLUSIONS

Only a fraction of the nation's estimated total coal resource can be regarded as economically recoverable, now or in the future, even allowing for higher prices which would permit extraction under more costly 79

mining conditions than can be entertained today. The fraction economically recoverable is relatively high for the subbituminous coal and lignite of the Western Plains but, pending technological advances in the underground mining of steeply pitching and severely disturbed seams, the economically recoverable fraction of the bituminous coal of the western mountains must be regarded as very low.

A substantial increase in prevailing coal prices (FOB mine) will be necessary before large-scale recovery of subbituminous coal by conventional underground mining methods becomes economic. However, when that price rise does occur, it will result in an increase of several billions of tons in economically recoverable reserves.

It is regrettable that, at s time when the nation's energy policies are under review, so little of the data needed for meaningful economic analysis of Canada's coal resource are available. A joint Federal- Provincial drilling program now underway in Saskatchewan and the similar program under discussion for Alberta and B.C. should contribute much new information. It is hoped that a systematic approach like this can be extended, with the results to be reported in a form which will permit economic analysis.

The mining companies could also appropriately be encouraged to undertake more extensive exploration. At the moment, however, the quantity of proved reserves is so large in relation to the scale of production that the companies have little incentive to explore for coal (particularly underground deposits) which will obviously not be mined during this century.

ACKNOWLEDGEMENTS

The writer acknowledges with thanks the constructive comments offered by his Luscar colleagues. He is also indebted to Mr. M. H. Allan of the Saskatchewan Power Corporation and Messrs. J. J. Crabb and R. Crisafio of Crows Nest Industries Limited for their critical reading of the paper in draft form. 80

REFERENCES

1. B. A. Latour, and L. P, Chrismas. Preliminary Estimate of Measured Coal Resources Including Reassessment of radicated and Inferred Resources in Western Canada. GSC Paper 70-58, Geol. Sur. Can., 1970.

2. Department of Energy, Mines and Resources. An Energy Policy for Canada. Ottawa 1973.

3. Alberta Energy Resources Conservation Board. Reserves of Coal, Province of Alberta. ERCB - 73-31. December 31, 1972.

4. National Petroleum Council. U.S. Energy Outlook; Volume Two: Report of Coal Task Group. November, 1971.

BIBLIOGRAPHY

1. N. Berkowitz. On Meeting Energy Needs with Canadian Coal. Fuels Planning Conference, Toronto. Octot ::, 1972.

2. B. R. MacKay. Coal Reserves of Canada. Reprint of Chapter 1, Appendix A of Report of the Royal Commission on. Coal, 1946.

3. Proceedings: First Geological Conference on Western Canadian Coal. November, 1971. Research Council of Alberta. Information Series No. 60.

4. Statistics Canada. Coal Mines 1971. Cat. 26-206, annual, January, 1973.

5. Statistics Canada. Coal and Coke Statistics, monthly report. Cat. 45-002.

6. U.S. Bureau of Mines. Cost Analyses of Model Mines for Strip Mining of Coal in the United States (based on 1969 cost levels). (Washington) U.S. Department of Interior. IC 8535, 1972.

7. U.S. Bureau cf Mines. Coal Resources of the United States - January 1, 1967. (Washington) U.S. Geological Survey Bulletin 1275.

8. U.S. Bureau of Mines. Strippable Reserves of Bituminous Coal and Lignite in the United States. (Washington) Information Circular 8531, 1971.

9. L. P. Chrismas and M. K. McMullen. Coking Coal in Canada. Mineral Resources Branch, Department of Energy, Mines and Resources, Ottawa. Mineral Bulletin MR 135, 1973. 81

URANIUM AND THORIUM: FUTURE ENERGY SOURCES by R.E. FOLINSBEE, F.R.S.C, University of Alberta, and A. P. LEECH, Ottawa

Whose bread I eat, His song I sing.

Let us as authors acknowledge that we come from a province which has had a period of unprecedented growth through development of petroleum and natural gas resources, and from a city with a long association with the mining industry of northern Canada. This paper is an overview of the Canadian and world uranium and thorium supply - demand situation as seen by two interested geologists-at-iarge.

1000- - Beyond 2100, mankind's energy needs must be met 800-- by a combination of coal, nuclear power, and I 600- - solar energy - beyond 2300, by technologies that are not yet known to be possible, much less 400- - economical.'

200- - Overpopdar.cn ^/

T'ang PAPEH P8NTEO MONEY BOOK PIAYING IOOO voi CARDS ENCYCLOPEDIA

RELATIVE S^NDARD OF LIVING

800 1000 1200 1400 1600 1S00 2000 AD. -YEARS- Each advance of man from ihe primitive state has been accomplished by a break-through in energy utilization, from digging sticks, through flint and fire, to the use of metals, water,, domestic animals, agriculture and the pure energy minerals coal, oil, natural gas, and now uranium. Each of the energy revolutions has involved some reluctance about acceptance, a period of acceptance and expansion, an exhaustion of the energy push, and up to now, decline and fall of the empires. China's long history illustrates the inter-relationships between energy supply and the standard of living . 82

Canada has gone thr&jph an impressive 25-year period of growth in production of the energy minerals - oil, gas and uranium. The plateau has been reached in oil and gas production from the Western Canadian basin and the situation on the frontiers is an uncertain rme. Canadian coal faces transportation and environmental problems. Thus, we look directly or indirectly ro the nuclear fuels,, uranium, thorium, deuterium and hydrogen for future energy supplies.

90s

ESTIMATED GROWTH IN OEMAKD FOR UjO. t MIECTED MTAtS.1

Uranium production, under nuclear weapons impetus, soarsd to a peak in the late 50's and then like Icarus crashed,, as the weapons game went underground and supply contracts vanished. The slow revival of uranium as a peaceful energy source has collided head on with environmentalists and the no-growth ethic, but nuclear energy has advantages that suggest that its 5 year doubling rate will persist - a rate of change unprecedented in the history of mankind. The growth in demand for U3O3 has been sstimated to far surpass that for most ex our common metals . Uranium is portable. Nuclear fuels are small in bulk and easy to transport. The daily production of seven tons of U3O3 from Rabbit Lake, Saskatchewan could be transported to Germany as excess baggage on the Lufthansa flight out of Toronto. 83

How Electric Power Sources Compare^

1 pound of coal (It) produces 1.5 kilowatt hours

1 pound of oil (2$) produces 2.0 kilowatt hours

1 pound of gas (10$) produces 2.2 kilowatt hours

1 pound of natural uranium (^$20) produces 29,000.0 kilowatt hours

The energy released by the fissioning of just one gram of uranium235 or plutonium239 or uranium233 equals the heat of combustion of 2.7 metric tons of bituminous coa! or 13.4 barrels of crude oil 4.

The 4 million pounds annual production of U3O8 from Rabbit Lake, (costing $30 million), burnt in inefficient conventional reactors, will provide Germany with 116x10 kwh of electricity, now produced from about 70 million barrels of petroleum liquids (costing $300 million). Fully burnt in breeder reactors the some uranium has the energy equivalent of 24 billion barrels of oil, worth $100 billion. Once built, nuclear power plants produce 14 kwh of electricity from one cent's worth of fuel - an order of magnitude more cheaply than from any fossil fuel source, though capital costs are higher. Little wonder that Japan, West Germany, Britain and Spain have contracted with Canadian producers for over 65,000 torts of U3O3, one quarter of Canada's measured reserves.

In discussing the world's energy supply, Cheesman^ has suggested the use of a manageable energy measurement unit called a Q, defined as 10'° BTUs (one million trillion BTUs). Using this unit, he estimated the total recoverable world supply of energy at 282.1 Qs, 69 Qs to come from known low cost uranium ore reserves available at a price of $10 lb. or less, burnt in conventional reactors. Burnt in a fast breeder reactor, uranium resources would extend the world's uranium energy supply to 420,000 Qs. These would be sufficient to fuel the world into the 38th century even at the present 6% annual growth rate in energy use. Because of the fuel economy of the fast breeder, the uranium resource base will be immensely expanded.

Canada's energy reserves (known and measured) as estimated by the CNA may be converted to Qs and roughly compared with Cheesman's world resource (geological potential).

From now on, demand for uranium oxide will increase steadily and exponentially at a nearly 5 year doubling rate *'°. By 1985 annual requirements are estimated to exceed 100,000 tons of U3O8 while the cumulative grand total will he over 1,000,000 tons. 84

Energy Sources Energy Reserves Qs(1018BTUs) World Canadian Total Resources^ Reserves'*

Coal 170 1.064 Oil 13 0.004 Natural gas 10 0.043 s (enriched uranium) 69 2.215 Nuclear -v (fasf breeder ) (420,000)* Fusion deuterium (10 billion)* Oil shale and tar sands 20 1.015 Hydro 0.1 0.002 annual Geothermal, wind, tidal 0.1 282.1 Qs 4.3 Qs "Technology not presently available. WORLD URANIUM REQUIREMENTS & RESERVES

Thousand Requiremsnts Thru 1985 Reserves-$10/lbU3O8 % Tons U3O3 Tons U3O8 Canada 15 1.5 United States 330** 29 United States 474 47.5 So. + Southwest Africa 300 26 Japan 106 10.5 Canada 236 20 United Kingdom 92 9 France,Gabon, Niger 124 11 West Germany 65 6.5 Australia 92* 8 France 40 4 Others 68 6 W. Europe other 107 11 TOTAL 1150 100 Foreign other 101 10 *Recent W. Australian discoveries have TOTAL 1000 100 increase• • a^v • -^r «B v«^ d«^ thi• • • p sw fiaurw • £* ^^m evi* t« o^^ 150.00• ^^ ^^ g -^r •«*• 0•«*- tons *Gu!fl7 figures are 420,000 tons 85

These requirements, nearly half by the USA, can be met by known reserves exploitable at less than $10/lb U3O8 mined in the United States, Canada, South and Southwest Africa, Australia, France, Gabon and Niger'. By 1985, the price tag will probably be up to $15/lb# unless another Is to 2 million tons of low cost additional reserves are discovered and developed. °

Runnalls2 estimates that by 1975 growth in demand for U3O8 will out- strip the estimated production of present (or planned) mines, ana by 1980, even flat-out production will not satisfy the more than 300 hungry reactors presently operating, under L. construction, or on order. In 1972 8 alone, 56 nuclear power reactors with 2 a combined output of 54,640 MWe were ordered by countries of the western world; they will be operational by 1980, and in Gilchrist's : 40-- opinion , may face a fuei shortage - critical, naturally. so ° """^ •" """• On October 6, 1973 the USSR entered the western world uranium 20+ Jllllllllllllllllllli"1 market with a 700 ton sale of enriched uranium through the EEC to West German utilities. This recognition of uranium as a commodity by the USSR may foreshadow large future sales by this mineral rich nation. ^2 1972 1975 1980 YEAR- Canada's measured reserves of ANNUAL WESTERN WOOD U3Oj PRODUCTION VERSUS DEMAND. 1972-1980 uranium (and thorium), presently one- fifth of the world's reserves and falling as exploration moves elsewhere, are sufficient for our needs in any conceivable eventuality for the rest of this century, and our resource base (geological potential) is very large indeed, though unmeasured. Over 90% of the operational Canadian uranium industry is concentrated in one small area of Ontario at Elliot Lake, where two major companies, Denison Mines and Rio Aigom, control most of the action and 20% of the world's low cost $5 - $10 uranium reserves '"/^ ^ . « 86

North South

\\\\V Legend

Diabase ETfl Espanola greywaclce

Bruce limestone

Bruce conglomerate

Misussagi quartzito

Arg.ll.te

Mem Ore Zone

Upper Ore Zone

Basement complex 0 100 200 DENISON MINES LIMITED GEOLOGICAL SECTION THROUGH Nol&No2 SHAFTS LOOKING EAST

At Denison, sprawled over 4700 acres, a 16 foot continuous bed of quartz-pebble conglomerate averages 0.15% U3O8 per ton (3 lbs per ton) in channels of the ancient pre-Huronian surface of the Quirke Lake syncline '"' . Initial reserves were established as 300 x 10° lbs U3O8. As a dividend, these conglomerates contain 0.02 - 0.4% ThO2, most of which could be recovered cheaply along with the uranium and stockpiled for future use '^ . Denison, after Roman's 1971 brush with the federal government blocking a $100 million sale of control to a foreign corporation, is moving its uranium exploration effort out of Canada, to conduct prospecting and drilling operations in northern and western Australia and the Powder River Basin area of Wyoming. 87

NORTH

In Canada, the Agnew Lake conglomerates are a vertical version of the PRE5ENT Elliot Lake conglomerates, with uranium and thorium content reversed: there are 3 ibs of thorium for every pound of uranium, which is present only as sub-ore grade at present prices . Exploration efforts continue for more uraniferous conglomerates in favourable areas of Canada.

Eliiof Lake Area In South Africa, another 20% of the world's uranium resources are found in placer channels along with gold washed SOUTH NORTH off an ancient Precambriar. terrain '^r'4. Since uranium is recovered as a by- product of gold mining, we might expect extra availability of South African uranium on world markets as a resuit of the recent surge in gold prices. As with the thorium at Elliot Lake, it would be cheaper in the long-run to recover and stockpile uranium now rather than retreat cemented tailings later.

Canada's crown corporation, Eldorado Nuclear Ltd., began success- w fully on Great Bear Lake and at the Beaverlodge (Goldfields) area of Agnew Lake Mines Ltd Saskatchewan, but despite this early start, lack of exploration funds and KBUGE25DO8P continued mining have reduced total reserves to only 2,803,200 tons containing .22% U3O8 at the end of 1972 9 (12 million lbs U3O8) .

RAND-BASIN Meanwhile, south of Lake Athabasca, MokS-a, a French government company, though unable to buy uranium directly

Kilfimtttrs from Canadian producers because of the \ w /'0 50 100 150 weapons clause, undertook an exploration \ .4 VKGM program in the Carswell dome area, an

Rand Basin showing locations of major drainage entry 88

Signif icant >S 500,000,000 >Si,ooopoopoo

diitricfs of United States & Canada

astrobleme produced by meteor impact. Here at Ciuff Lake, Mokta outlined a 45,000 ton orebody averaging 10% U3O8 ^° Although Mokta has spent $11 miilion on exploration in Canada since 1963, expenditures in the Carswell area were only $5 minion to find 9 million pounds of uranium that may be shipped to France, once the French finish their weapons testing. Meanwhile; Canadian restrictions on control by foreign companies have shifted Mokta's exploration interest to the USA, where uranium exploration costs average about $ l/lb l^Og discovered *'.

The major petroleum companies, Gulf Oil in particular, are becoming total energy companies. On the other side of the Athabasca sandstone basin at Rabbit Lake, Gulf Minerals, with minimal exploration expenditures, found a $500 million secondary enrichment of uranium in Precambrian sediments which will become a mine in 1975, milling 2000 tons per day from 0.35% ore, for a 20 year annual output of 4.5 million lbs l^Og, contracted in advance to partner Uranerz of West Germany 1°'*" .

South of the border, in the world's greatest energy consuming nation, the U.S.A., we see Canadian money developing uranium reserves for a protected market . Rio Algom, Kerr Addison and Noranda have discovered rich mines in the western States where one-third of the world's uranium reserves have been developed. This RQ

uranium was leached from volcanics, concentrated in ancient river chc.inels and reconcentrated by solution and reprecipitation.

WORLD URANIUM & THORIUM DEPOSITS & PRODUCERS (after GriKtth.1967)

Principal frodiKiri SiDtpouts oo ot Vffl O Uronjufn Dffpostf Q Thorium Depour

France and Australia share the last major chunk of reserve pie.

In addition to their efforts in Canada. French geologists went prospecting in other former colonies, Niger and Gabon, with the object of finding a few dozen 1500 ton U3O8 deposits at strippable depths. In Niger, sedimentary Jurassic and Carbonaceous uranium deposits lie !.n permeable channels where uranium, weathered from volcanic tuffs, was trapped by organic material in ancient stream beds.

The R<5«/est uranium discoveries have been made in Australia e where there was once only a smal! production facility at Mary Kathleen, a unique rare-earth" uranium orebody, and a high-grade deposit ar Rum Jungle in the Northern Territory. The inflated newspaper eslimates of reserves by Queensland Mines for the Nabarlek depositsjn an aboriginal reserve of tWe Northern Territory, deluded the Australian public along with Noranda, which ended up with Jim-Jim as a consolation prize,

potential.at Ranger, 140 million lbs. of U3O8 in^p shallow brebody^^ iJ;' high grade compared to the underground Canodian Elliot Lake deposits. 90

jiir. ji

URANIUM IN AUSTRALIA

Mill 300

Most recently. Western Mining, a gold mining company with an aiert staff, threatening INCO in the nickel industry, has come across a 100 million lbs uranium reserve in calcrete, a near surface ground water deposit at Yeelirie in Western Australia, next door to the fabulous iron mines . Asarco followed up with a similar deposit at Maitland Lake. So, beginning from one small producer, Australia has developed reserves comparable to those of Canada. The recent change in Australian government threatens to put a damper on down under and the wooily question of aboriginal rights has risen.

South America will probably be next on the list. As geologists, it seems incredible to us that major uranium ore deposits have not been found in outh America where there is no shortage of likely uranium sources, old shields with uranium in conglomerates or at unconformities and a great mountain mass shedding sediments and volcanics to the east, which should create Utah-Wyoming type roll deposits. It was as late as 1952 that Steidle, Dean of the School of Mineral Industries at Penn State, said in a mineral forecast for 2000 A. D., "No important sources (of uranium) are generally known within the confines of the United States"!20

So far, we have talked only of rich uranium deposits capable of producing at $5 - $10 per 1b U3O8. But as an energy mineral, uranium is competitive at much higher price levels. Doubling the price of U3O8 at the mine results in a negligible increase in the cost of power from a CANDU reactor at Pickering, Ontario, as 91

NON COMMUNIST WORLD CUMULATIVE UtANIUM KQU&EMENTS t4 TKROUOH 2000

wot ID — RKOURCES O

ESTIMATED ADDITIONAL (POTENTIAL)

$10-13

REASONABLY ASSURED < (RESERVESI ($10

1980 1990 2000 YEARS

U.S. URANIUM RESOURCES AT $ 10 TO $200+? PER LB U3O8

S200*? t 4000 4 S20C+ 1800-"

$50 9, 6-- 3 $30 510 2-- CONVENTIONAL SHALE SHAIE GRANITE »1ALE GRANITE SEAVATER 60-60ppm 2S-60ppm"K)-20ppm lO^Sppin 4-)0pp

opposed to the marked effect of Alberta's doubling of the gas price at wellhead on the economics of fueling the Hearne thermal station.

Moderate increases in the price of l^Og iead to vast increases in resources. At higher prices many different types of ores can be considered, niobium-uranium bearing carbonatites, granites, pegmatites and migmatites, uraniferous shaies and phosphorites, even sea water. Uranium and thorium recovery as by-products becomes economic.

The shelved Agnew Lake mine of Kerr Addison containing three pounds of thorium for ea~h pound of uranium could be opened and the thorium used as base load in efficient high-ramperature gas reactors. Gulf's experimental high-temperature reactor going on power at Ft. St. Vrain near Denver is the first of 8 contracted reactors of this type, destined to produce more than 7000 MWe", roughly equal to the Ontario CANDU program to 1983. The Gulf HTGR is said to be more efficient than present light water reactors, operating at 900°C with a 45% efficiency and only 1° thermal pollution. Gulf has arranged under license to supply the HTGR to German and French industrial groups and is negotiating internationally - tough competition for CANDU.

Even with the advent of tl e breeder reactor a critical decade for uranium supply will arrive in the 1990's; it will pose problems comparable to the petroleum crisis of the 70's. Uranium reserves not needed until the 1980's or 90's have little present worth. Prospecting for uranium should pick up after 1975 when companies, now spending scarce dollars on 'non-return' exploration, begin to generate larger cash flows from producing mines. Denison, with its mine and mills paid for years ago by defence contracts, would have been an attractive bargain for the CDC at the 1970 offering price of $100 million for O5% control, a deal blocked by the Canadian government.

Over the long term (21st century), the law of least effort will inevitably push the world energy system in the direction of a nuclear-hydrogen economy. Uranium as a fuel lies in the shadow of fusion; deuterium and hydrogen will certainly displace uranium, as coal was displaced by oil and natural gas. It is this long technological shadow, not any shortage of uranium prospects that inhibits commitments on the part of nations and energy companies towards uranium prospecting or acquisition of large utility fuel inventories. Japan and Germany, have-not nations in the energy field, have made the major commitments and are moving rapidly towards nuclear based economies2', along with Britain and the United States whose industrial might has long been based on cheap energy and the law of least effort.

From the standpoint of the law of least e '*ort let us compare the highly touted Syncrude Alberta oil sands project v/ith Gulf's Rabbit Lake uranium mine, located in comparable areas. 93

Syncrude Rabbit Lake

Capital cost $1000 million $50 million

Work force 1500 directly 210 commuting by air 8500 indirectly little indirect employment

Product and value 125,000 bl. oil day 15,000 Ib U3O8 $500,000 $150,000 day Reactors Energy equivalent 125,000 bl. oil Conventional 300,000 bl. oil CANDU 1,000,000 bl. oil Breeder 90,000,000 bl. oil

Profitability Nil High (capita! and tax generating prospects)

Environmental effects Heavy SO2 emission in a Removal of a local confined river valley. radiation hazard. Thermal pollution of Athabasca River. Creation of boom town subject to technological obsolescence. Unpredictable effects on an important wild-life delta.

In one year 200 men commuting into Rabbit Lnke would produce as much energy fuel, used in the breeder reactor, as 45,000 m ~ exhausting the mineable tar sands through labouring at 30 tar sand plants for a lifetime.

Within a two mile radius of this national library lie 200,000 tons of U3O8, roughly the equivalent of the measured Canadian reserves of uranium ore. About half of this might be recovered from the granites that underlie the city of Ottawa, mined to a depth of two miles; from the west's point of view perhaps not a wholly bad solution to the east's energy problems. Cost would be about $50 a pound of U3O8/ ten times costs with present ore grades.

There are many wilderness areas where such mining may even now be economically feasible. At Rossing in South West Africa Rio Tinto Zinc is said to have an immense orebody containing 1.4 pounds of uranium oxide per ton. Rio Tinto her. announced firm contracts to supply the UK Atomic Energy Commission with 7500 tons of U3O8 worth «*f?38 million between the years 1970 and 1980. It will operate an open pit mine that will employ about 700 European miners and 1000 Africans. 94

Stories are rife.One quoted by Richard West22 ;s that a geologist first checked the site for uranhm -hen he read that an African chief in bygone days had seni his wives to Rossing to make them sterile - a story probably only the result of a fertile imagination. A preliminary isport published on the Rossing uranium deposit" suggests that it is an area injected by lens-like radioactive psgmatites that lend rhemseives to open pit mining and concentration. The area is said by the Rand Daily Mail of February 1970 to be five miles long and one mile wide. At an average grade of 1.4 !bs U3O8 a ton mineable to a depth of 300 feet the Rossing deposit would contain 3,000,000 tons of U3O8/ thrice the measured reserves of the world.

This brings us to a final point - the uranium mystique. Uranium hcs an odious association with the bombs crouched like trap-door spiders at the base of a thousand missile silos, or lying pupate in atomic submarine pods and the bays of bombers droning 24 hours a day across the vorld. During the 1940's we as Canadians participated, somewhat unknowingly, in the opening of Pandora's box. Source of the uranium and plutonium in the two deadly insects that stung Japan is shrouded in the veil of secrecy that still envelopes the Manhattan project. However, one of us, co-pilot on a Liberator bomber headed for reconnaissance over the immense reaches of the Pacific, rejoiced at the early end of the war. During the 1950's, though knowing the devastation wreaked at Hiroshima and Nagasaki we scrambled for contracts to supply uranium for the arsenals of the Western World. In the late sixties and seventies our policy seems to have been one of trying to close Pandora's box on its original troublesome contents, under the pressure of statements such as that by Richard West in "River of Tears" -

"This new process [of uranium enrichment] , as I have set out to show, is possible because of the big new supply of uranium from the Rossing mine. The British government and RTZ not only give moral support to South Africa's illegal rule in South West Africa but supply the racist regime with the means to make nuclear weapons. "

Pandora's box can never be closed, and it might be well to remember the rest of the Pandora legend. Although she was sent to punish mankind for discovering that primitive energy resource, fire, in the end Pandora closed the box on Hope. There is one faint hope for the world - that uranium, thorium and deuterium may produce the energy necessary to set the world free from the nightmare demands of lebensraum and co-prosperity spheres, and we should set ourselves to the giant task of unlocking this hope chest. An unclear energy future becomes nuclear by a single transposition.

Acknowledgments The literature search on which this paper was based was supported by the National Research Council of Canada. The authors are deeply grateful to R. M. Williams, H.B. Merlin and O. J. Runnalls of the Department of Energy, Mines and Resources, to Wm. Gilchrist, Roger Blais and CF. Smith of Eldorado Nuclear, to 96

N.M. Ediger and L.T. Gregg of Gulf Oil, to A.F. Lowell of Rio Algom mines, to Denison Mines and to colleagues at the University of Alberta for pertinent information and advice 22-31 ^ Redrafting, mostly from EMR and USAEC sources wos by Frank Dimitrov and the paper was set up and lyped by Doreen Haugan of the Department of Geology.

REFERENCES

1. E. Cook, Technology Review, 74, No. 12, 16 (1972).

2. O.J.C. Runnclls, Can. Nuclear Assoc. Mtg., Paper No. 604, June (1973).

3. Nuclear power and environment in Canada, Can. Nuclear Assoc. (1971),

4. M.K. Hubbert, Bull. Can. Inst. Mining and Metallurgy, 1, July (1973).

5. W.J. Cheesman, Financial Times of Canada, July 9, 15 (1973).

6. R.D. Nininger, U.S. Atomic Energy Commission, Nuclear Fuel Resources and Requirements WASH-1243, 26 (1973).

7. J.W. Griffith, Mineral Report No. 12, Mineral Resources Division, Dept. Energy, Mines and Resources, Ottawa, 52 (1967).

3. R.M. Williams, Can. Mining Journal, 94, Feb., p. 100 (1973).

9. W.M. Gilchrist, Eldorado Nuclear Ltd., 1972 Annual Report, 1, 3 (1972).

10. J.A. Robertson, Can. Inst. Mining and Metallurgy, Trans., LXX1I, 166 (1969).

11. Denison Mines Ltd., Uranium the Energy Mineral (1969).

12. S.M. Roscoe, inG.S.C. Paper 66-12, 11 pp (1966).

13. D.S. Robertson, Uranium Exploration Geology, in International Atomic Energy Agency, Vienna, 267 (1970).

14. H.C.M. Whiteside, Uranium Exploration Geology, in International Atomic Energy Atency, Vienna, 49 (1970).

15. The Northern Miner, 59, No. 16, 1 (1973).

16. The Northern Miner, 59, No. 13, 1 (1973). 97

17. Gulf Oil Corporation Annual Report, 36 (1972).

18. G.C. Hardin, Future Energy Outlook, Colorado School of Mines Quarterly, 68, 163 (1973).

19. U.S. Atomic Energy Commission, Nuclear Fuel Supply, WASH-1242, 9 (1973).

20. E. Steidle, Mineral Forecast 2000 A.D. Penn. State College Bull, ?9, 119 (1952).

21. S. Matsune, Financial Post, Sept. 22, J-18 (1973).

22. R. West, River of Tears, Earth Island Limited, London, 72, 75 (1972).

23. J.W. von Backstrom, Uranium Exploration Geology, I.A.E.C., Vienna, 143, (1970).

24. L.T. Gregg, Capita! Requirements of the Canadian Nuclear Power Program, CNA'73-502, Can. Nuclear Assoc., June (1973).

25. H.B. Merlin, Can. Nuclear Assoc., 71 -CNA-301 (1971).

26. N.M. Ediger, Calgary Br., Can. Inst. Mining and Metallurgy, Jan. (1973).

27. W.M. Gilchrist, President's Address, Can. Nuclear Assoc., CNA'73-205 (1973).

28. Imperial Oil Review, 57^, No. 2, 16 (1973).

29. D. Lowry, G.W. Nicholson and Company Ltd., Analysis of Denison Mines Ltd., 7 pp., April (19c6).

30. A.F. Lowell, Rio Algom, Intra-company report on uranium (1973).

31. U.S. Energy Outlook, Nuclear Energy Availability, National Petroleum Council (1973).

32. New York Times Service as reported in Edmonton Journal, Oct. 6, 37 (1973); Thomas Land, Financial Post, C-7, Oct. 27 (1973). 9 9

DISCUSSTOw OF SESSION I

L/K. BEN HOGG (University of Winnipeg) : Ir. the papers in this session, the conventional units associated with each resource have been employed: oil- in barrels, gas in cubic feet, coat in tons, and I!^0g in tons; and various energy units. The equivalence in terms of energy is not obvious to me and I would hope that a simple unit common to all energy resources could be found. EDITOR: The reader is referred to the Glossary (P.473) for some help in this connection. DR. P.J. DYNE (Whiteshell Nuclear Research Establishment): To put the long-term potential of nuclear energy in perspective it is useful to express the energy content of our uranium in terms of equivalent barrels of oil. At this meeting Folinsbee and Leech told us that the single deposit at Elliott Lake contains 2 x 10^ tons of U-jOg. For an order of magnitude calculation we can take this as 2 x 10 tonnes of UO2. Irradiation in a CANDU reactor to 8000 Megawatt days/tonne releases 1.6 x 109 Megawatt days or 3.84 x 1013 kWh. Noting that 1 barrel of oil = 5.8 x 106 BTU or 1.7 x 103 kWh (106 BTU = 293 kWh) we find that the Elliott Lake deposit is equivalent to 3.84 x 1013/1.7 x 103 = 22 billion barrels of oil.

In other papers Mclvor and Lougheed estimate that 16 billion barrels of oil have so far been discovered in Canada, and Govier estimates that 27 billion barrels of synthetic crude could be recovered from the tarsands from near surface deposits. This one deposit of low-cost uranium ore is therefore equivalent in energy to our known petroleum resources and is comparable to the readily recoverable resource in the tarsands.

In addition, the spent fuel from a CANDU reactor contains plutonium whose energy equivalent is roughly equal to energy extracted from the original fuel. By processing and recycling the plutonium we could extract a further 20 billion barrels of oil-energy equivalent from this "waste" material.

The appeal of the energy resource argument for the breeder reactor is seen by noting that the energy content of the U-235 and U-238 (if it were possible to burn all the U-238) in the Elliott Lake deposit would be in the order of 2000 billion barrels TOO

of oil. This is of the same order as estimates of the total world oil resources and yet to be discovered (Hubbert, Scientific American, September 1971).

MR. JAMES C. BROWN (Shell Canada): Does the Geological Survey of Canada plan to publish a third estimate of Frontier oil potential in 1974 to follow up the 1972 and 1973 estimates published in the Energy, Mines and Resources green paper?

DR. McCRQSSAN: The Geological Survey of Canada will be involved in an on-going program to maintain estimates of the petroleum potential of Canada. This is being done through a departmental sub-committee with membership from various other branches as well as from the Department of Indian and Northern Affairs. In view of the continuing changes in the data base, the estimates must be revised on a regular basis. I might add that even the already published estimates, because of the short time available in which to pre- pare them, were not able to take full advantage of even all the data available at that time, and further work is necessary to improve their quality on that basis alone. I am not in a position to say when the results of further studies will be published. This decision will be made by our senior management.

MR. BROWN:

In view of the uncertainties in these forecasts} is the Geological Survey of Canada making estimates of the amount and rate of exploration (sampling procedures) which is required before a firmer estimate of this potential is obtained? DR. McCROSSAN: Yes, we are mindful of exploration activities in any areas being evaluated, most particularly from the point of view of the degree to which various plays have been tested and the amount of effort needed to fully evaluate the possibilities of the various geological configurations within the basins. I think this would be what you referred to as sampling, We would look upon each play as being sub-population to the sampled. Perhaps we should consider the degree of exploration effort necessary to adequately sample a play in relation to our probability estimates of a certain quantity of hydrocarbon being present. I feel that we need further work in this area to improve our techniques before it can be considered statistically rigorous. 101

MR. JOSEPH YANCHULA (Consulting Petroleum Engineer, Calgary):

Dr. McCvossan's conclusion that "the distribution of the • • various types of hydrocarbons in a sedimentary basin is •''I quite orderly and to some extent -predictable" does not Si appear to be warranted. From the evidence in his own '; \ paper it could be more logically concluded that the distribution is both unknown and completely unpredictable. : ' We do not even know how much oil was initially formed in a particular basin3 let alone trapped. In western : Canada approximately 95 percent of the oil is thought to be in the tarsands. How do we know it isn't only 90%? Even such a small error could mean that there • could be twice as much conventional oil left to be found as new expected by most geologists. The small ~ proportion of oil or gas in the Permian and older formations can probably logically be explained by the small proportion of the wells which penetrate these deeper formatioKo. Stratigraphic traps are particularly difficult to locate and it is quite possible that an unusually large quantity of oil is located in these trapse particularly in the deeper, older inadequately explored formations. The Pembina field is the largest •• in Canada and happens to be a stratigraphic trap. If L: it had been in an older formation at a substantially ; greater depth it may not have been found. DR. McCROSSAN:

These questions are provocative and helpful in demanding clarifica- tion of statements that were, for lack of time, perhaps too simplistic. I must apologize for the length of the answer but the issues raised are complex and philosophical.

When I said that "the distribution of hydrocarbons in a sedimentary ~ bssin is quite orderly and to some extent predictable," I was referring specifically to the geochemical distribution. This phenomenon is particularly well displayed and is reasonably well documented in the structurally simple Western Canada sedimentary basin. It can be seen that the hydrocarbons grade as a result of . thermal maturation from immr.ture at shallow depth in the form of uncracked kerogen and methane derived from bacterial decomposition of organic material, to oils and gases at medium depths and more elevated temperatures which grade progressively to smaller and >i simpler hydrocarbon molecules with increasing depth and tempera- \ ture forming lighter oils with increasing proportions of higher molecular weight gases such as propane, butane, etc., to only f K gas with condensate and eventually to nothing but dry gas or l e methane in the deepest parts of the basin. In detail, this \ relationship is somewhat more complex in that it depends on other j' factors such as the ancient maximum depth of burial before -\. erosion of the surface to its present level, geologic age of the J deposits or the time which the hydrocarbon was subjected to a j 102

particular temperature, etc. In addition, the uppermost edge of a basin may contain a heavy oil belt such as occurs in Alberta formed by the bacterial degradation in the near surface zone of oil escaping from source rocks deeper in the basin. In many basins this shallower flange has been removed by subsequent erosion. With an understanding of the geological and geochemical history of a basin, one can predict the type of hydrocarbon that can be expected in certain parts of a basin :Lf_ it were generated from suitable source rocks and caught in suitable traps. Fairly early in exploration of a basin it is possible to determine whether suitable source rocks are present and to some extent whether suitable trapping configurations are likely tr be present. Thus when hydrocarbons are present in a basin they ar a arranged in an orderly sequence with respect to the basin geometry but that does not tell us whether or where within a particular slice of sedimentary volume commercial pools will be found. Orderly is not synonymous with uniformly.

In reality, we find many basins^ with little or no generating capability or others lacking suitable traps in place at the time of hydrocarbon migration when sedimentary loading was taking place. Within a petroleum-prone basin there are only certain places where conditions were optimum for accumulation. In principal, then, the occurrence of hydrocarbons is quite orderly in that they are distributed according to a relatively well understood set of conditions. These necessary conditions can only be established by drilling, and with an increasing information base one can be more and more certain in prediction.

If we knew absolutely nothing about a particular sedimentary basin Yanchula's observation that the distribution is both unknown and completely unpredictable would be correct. The continental rises aoout which we know very little are such a case, involving certain hypotheses which will not be tested for many years when the technology becomes available. Yanchula's observation is not warranted for basins where a reasonable amount of exploration has taken place. In the case, for instance, of the continental shelves where a large amount of high quality marine seismic data is available a few wells can provide c:agnostic answers relatively early in an exploration program.

It is true to say that we do not know how much oil was originally generated in a basin but it is safe to say that it was vastly in excess of the amount trapped. If any amount of reasonable source rock was sufficiently buried in a basin the original supply is not nearly the problem that trapping the migrating fluid is.

The proportion of the oil in the oil sands compared to conventionally trapped oil in the Western Canada sedimentary basin is, not particularly relevant to the amount of oil remaining in the basin since the trapping conditions as explained above were probably totally different, with the heavy oil entrapment being much more efficient. The quant-'.ty of heavy oil is not likely to 103 yield much information on the conventionally trapped hydrocarbon other than to indicate that hydrocarbons were generated from source rocks in the basin.

There will, indeed, be additional oil and gas to be found in the Western Canada sedimentary basin and from what we know of that basin it will almost certainly be in stratigraphic traps. The Geological Survey of Canada estimated suggest on the basis of the known geology in the three Prairie Provinces that there are 4.0 billion barrels of recoverable oil and 34 trillion cubic feet of gas in addition to the proven reserves. This will be almost entirely xn smaller pools and harder to find than that already discovered. With what is known about the distribution of rock types or facies in the various formations of the Western Canada sedimentary basin and the very considerable deep well control it is quite unlikely, but not absolutely impossible, that a stratigraphic trap the size of Pembina might still remain undiscovered. In general, as noted in the paper, the younger or shallower rocks contain by far the bulk of the world•s hydrocarbons.

DR. W.R. TYSON (Energy, Mines and Resources): Mr. Molvor refers in his pappy to a figure of 75% of Canada 's oil potential as being located in offshore deposits; however, very little has been said this morning about exploitation of this resource. Would Mr. Mclvor care to comment on the prospects of development of offshore technology ?

MR. MeIVOR; To amplify our presentation, some 47 billion barrels of Canada's mean undiscovered crude oil potential resources in the Frontiers are expected to lie in deepwater and ice-covered areas where the technology to explore and develop is only just materializing or does not yet exist. We have confidence of this expertise being developed, given the proper investment climate. Imperial has been working for some years on various concepts to drill in such environments and we are now drilling Imraerk B-48, the first well in the Arctic offshore, from an artificial island constructed in the shallow water of Mackenzie Bay. Additionally, construction is underway on a second artificial island from which ve intend to drill ftdgo G-28. It is our belief that for shallow water locations in the Beaufort Sea, a*; least out to 10" water depth, the artificial island concept will satisfy the requirements of both exploration and production. For greater water depths, Imperial is conducting research into the feasibility of bottom- founded structures of steel and concrete design. Other companies are also conducting research into means by which to drill in ice- covered waters. 1. An Energy Policy for Canada, Phase 1, Volume II, Appendices, Department of Energy, Mines and Resources/ Information Canada, Ottawa,' p-i 32. 104

In the Arctic Islands offshore, basic data on physical parameters such as ice conditions are still being gathered; however, the air cushion drilling system is one concept that may offer a feasible apprcich. Off the Atlantic coast, in addition to the problems posed by floating sea ice and icebergs, much prospective acreage lies under water depths exceeding the drilling and production capability of existing technology. Research and development of sea-bottom production systems is well underway. Industry has demonstrated the capability elsewhere in the world to drill in 1,500 feet of water in the floating mode, and drillships are now in operation with rated capability to 3,000 feet. It is anticipated that drillship capability can be extended to 6,000 feet. Beyond this, however, the technological requirements are undefined. It is i.Tiportant to note that acreage on the East Coast is presently held out to 12,000 feet of water.

MR. J. YANCHULA: Mclvor and Lougheed state that 16 billion of the 20 billion barrels of recoverable oil thought to exist in the western provinces has already been found. If this is so3 then an intelligent •premier of a western province would find it in his interest to raise royalties to as high a level as possible to maximize the government take rather than try to provide incentives to explore for such a small proportion of oil, so difficult to find. MR. MeIVOR:

By the end of 1972 the western provinces had remaining proven crude oil reserves of 8 billion barrels (excluding natural gas liquids). Accordingly, the mean potential crude oil reserves remaining to be discovered of some 4 billion barrels represent 50% of the oil remaining to be produced, hardly a small proportion. However, we agree with Mr. Yanchula's deduction that raising royalties to a high level might effectively eliminate tht, incentive to search for this crude oil = We suspect too that such an action would also affect the exploration for natural gas for which in the western provinces there is a higher proportion remaining to be discovered than is the case for oil. Certainly a higher royalty would reduce the cash flow which the Industry would have to finance exploration and development programs and this, along with the repudiation of the royalty provisions in existing contracts required to increase royalty, would severely lower investor confidence. 105

MR. J. YANCHULA:

Regarding oil in the frontier areas, Mr. Mclvor and Mr. Lougheed state that only 5 to 15% can be sold at current price levels. The remainder will have to be sold at prices in excess of $8 per barrel. At that price level it would be economical to make oil out of coal. Why disturb the Arctic ecology and run the risk of polluting the oceans by offshore drilling if the oil is so expensive? If makes neither ecological nor economic sense to go after frontier oils and governments would be foolish to encourage such activity.

MR. MeIVOR;

We would first like to correct the statement attributed to us by Mr. Yanchula. We said our analysis indicated directionally that between 5 and 15 billion barrels of Canada's undiscovered crude oil potential may become available at current prices (which we took at $4-$5/barrel), and that an additional 25 billion barrels may become available at prices up to $8/barrel. We said the remainder would require prices above $8/barrel. We agree with Mr. Yanchula that whether or not crude oil is obtained from coal or from the frontiers will indeed be determined by whichever source is the most economic, including environmental protection costs. In'our view, there is much frontier crude oil made from coal, but we also believe Canada should be developing the technology for all energy sources. Who can tell today with certainty which ones we will be successful in discovering and developing or precisely what the relative economics will be?

MR. J. YANCHULA; There is some possibility that the Arctic Ocean will become open water in 20 to 30 years. The thickness of Arctic ice has decreased from 43' 80 years ago to 6' to 8' today. Should the Arctic Ocean become open water, the cost of exploration, development and transportation of any oil found there would be greatly reduced. Risks of pollution would also be greatly reduced. The widely published theory that an ice-free Arctic Ocean would trigger another ice age has been thoroughly discredited. Periods of glaciations or ice ages are brought on by extraordinary solar activity.

MR. MeIVOR; Even if the hypothesis of open water in the Arctic Ocean by ths year 2000 is true, and we doubt that it is, can we wait 30 years to develop these potential resources? For example, the recent study, "An Energy Policy for Canada," suggests frontier crude oil supply will be required in the 1980's. 106

MR. YANCHULA: Mr. Horte has stated that it would cost 60 cents per Mcf to transport gas from the Arctic to the U.S. border. The wellhead price at the Mackenzie Delta in contracts signed by Imperial Oil was 32 cents per Mcf. This is a total of 92 cents per Mcf or roughly competitive with coal gasification or making gas from tarsands crude. Why not look to speeding up these alternatives if we start running short rather than saddle ourselves with a $6 billion outlay for a pipeline to a remote area?

Over half of the natural gas is currently used for industrial purposes. If a shortage should develop3 the largest industrial plants could be directed to use coal and the pollution problem could be eliminated by enforcing the installation of facilities to clean up flue gases. These are already in use in such cities as Hamilton.

The chief beneficiaries of the Mackenzie pipeline are the Americans because the Prudhoe Bay gas could be brought down somewhat cheaper than by liquifying it at an Alaska port. The corporations involved, mostly foreign, would also benefit, of course.

For Canadians, investment in a Mackenzie Valley gas pipeline would be economic lunacy. Only 400 permanent jobs would be created with the $6 billion investment compared to 400,000 jobs if put into secondary industry. There are multiplier factors involved but it is not too difficult to see where most jobs would be multi- plied with an investment of this magnitude.

If the Americans and the corporations wish to see the Mackenzie Valley gas pipeline built then they must offer the average Canadian, and particularly the northern Inuit and Indian people, a suitable quid pro quo. This, Mr. Horte and his associates have not even begun to consider. MR. HORTE: Mr. Yanchula makes the point that we should be speeding up developments with respect to coal gasification and making gas from tarsands crude because the cost of doing so would be about equal to the cost of Mackenzie Valley gas. However, I do not know what he bases this on.

To my knowledge there does not exist anywhere, at this time, a large-scale coal gasification plant in operation. While one or two are now being constructed in the United States, it will likely be some time before these are operating on a completely satisfactory basis. Furthermore, I expect the cost for such gas 107 will be in the order of $1.25 per Mcf. I think coal gasification will be attractive at some stage, but I fail to see why that possibility should deter us from developing now our hydrocarbon resources in the North. To the extent that the coal gasification is competitive, I am sure it will be developed.

With respect to manufactured gas from tarsands crude, it would seem to me that the more efficient way would be to leave this fuel in liquefied form and transport it to eastern Canada and burn it as liquefied fuel. This is a much more efficient way to transport BTU's. Certainly if you were to take tarsands crude and gasify it in eastern Canada, the cost would be far in excess of natural gas proposed from the Mackenzie Valley area. Burning it as liquefied fuel will probably be about the equivalent of the price of natural gas delivered from the Mackenzie Valley into eastern Canada. Further, in order to keep pace with the traditional markets for crude oil in Canada, we will need to be developing almost two tarsands plants a year by the end of this decade — a fairly sizable task in itself.

With respect to the direct-fired use of coal, I agree that more coal should be used for these purposes, and undoubtedly will, but again I do not see why this should cause us tc defer the development of our hydrocarbon resources in the North.

The only reason given by Mr. Yanchula for deferring the large investment in the pipeline facility is that the large investments will only create 400 permanent jobs. This ignores the thousands of jobs created in the manufacturing of the pipe, the compressor stations, etc., and in the construction and subsequent future expansion. But this is still only a small part of the permanent jobs created in the exploration, production, construction of gas plants and other facilities and service industries which have to support these facilities. For instance, all the pipelines in Canada employ only slightly over 3,000 people in their operations, but the oil and gas industry in western Canada depends upon these pipelines for transporting their product to market. In Alberta alone over 200,000 jobs are directly related to the oil and gas industry and this does not take into consideration the jobs created in the rest of Canada which supply annually about $500 million worth of equipment and supplies in supporting that industry.

Most important of all is the role that access to an ample and secure supply of natural gas at reasonable cost will play in facilitating the growth of production and employment in Canada. Recent events remind us of the hazard that an insufficiency of available and usable forms of energy could limit the growth of employment or even reduce employment in some circumstances.

Mr. Yanchula makes a statement that the chief beneficiaries of the Mackenzie pipeline are the Americans because the Prudhoe Bay gas could be brought down somewhat cheaper than by liquefying it at an Alaskan port. I do not quarrel with his statement that they 108

would benefit, but I wouU say that Canada would benefit even more in that this movement of a large volume of Prudhoe Bay gas, which coupled with Mackenzie Valley gas, makes it feasible for Canadians to obtain and develop their natural resources in the Delta area at a much lower cost than could otherwise be done. Certainly, dependent upon the Canadian market alone, the project would not appear to be viable any time in the near term when it will be required. Substantially larger reserves would have to be developed in the Delta and I expect you would see a deferment of exploration in this area if the project were dropped or postponed and, in the final analysis, we, as Canadians, would be the ones who would really suffer.

Mr. Yanchula's statement that we have not even begun to consider the northern Inuit and the Indian people reflects a lack of knowledge of what is being done. I do not believe any project in this country has devoted more time, effort and money to this problem than we have. For example, we now have a training program involving 75 northern natives with on-the-job training aug- mented with technical skill training in order that they can develop the skills required. We hope to expand this program substantially and to use these trainees to train other natives, not only in technical skills, but also in the supervisory and managerial areas. We have given full consideration to native concerns and are continuing to consult with the native organizations in the North, as well as the individual native communities. We have discussed with them the routing of the pipeline, the location of our camps and other factors which could affect their community, their trapping areas or their lifestyles. While we are not involved in the land claims situation itself, we have been doing everything within our power to encourage both parties to get together and arrive at an equitable settlement.

We would be very pleased, if Mr. Yanchula is interested, »o meet with him and explain in greater detail what we are doing in the many arsas of his concern. DR. J.B. WARREN (TRiUMP, University of British Columbia) asked Mr. Horte for certain data regarding the effects of pipe diameters and was provided with the following: Economies of Scale Relative to Proposed Mackenzie Valley Gas Pipeline Index Index of Cost Throughput of Service Outside Capacity * per Mcf Diameter (Case A = 100) (Case A = 100) Case A 48 inches 100 100 Case B 36 inches 48 150 Case C 30 inches 31 200 * Throughput capacity is proportional to the inside diameter of the pipe raised to the power of 2§. 109

PR. WARREN then raised a further point:

J think it is understood that changing pipeline size from 48" to 36" makes an important oost difference of perhaps 50% but this is not the significant pointy which is the total gas to be moved; linked to it, what is the likely percentage of the gas flow coming from the two fields? Presumably an -stablished capacity of around 30 T cu. ft. is the basic assumption made for economic viability of such a live. If the present established capacities are 23 T at Prudhoe and 7 T (a less certain figure?) at the Delta then one might assume a flow rate in this i-ztio from the two fields, not the 50-50 division which your talk, I think, implied.

There is, of course, no reason why a pipeline should not be built for the U.S.-origin gas, assuming that suitable rental conditions can be established, and if no gas existed in the Delta this might well have been the situation. However, I would hope you would clarify this matter in your answer. MR. HORTE; With respect to ratio of volumes from Prudhoe and the Delta, the facts are that the rate of natural gas production from Prudhoe will be less than one would normally expect from reserves of 26 Tcf. We anticipate deliveries of 2.0 to 2.25 Bcf/day. This lower-than-normal delivery rate is because a major portion of the natural gas will be produced with and dependent upon oil production from the field. With respect to deliveries from the Delta area, one would expect a producing rate from these non- associated gas fields to be approximately 1 Bcf/day from reserves of 7.0 Tcf. This means the 50-50 proportion referred to assumes additional reserves being developed in the Delta. From our studies we fully expect these additional developments in the Delta to take place and be available by the time the project is completed. The 48-inch diameter would still be the appropriate sizing even if initial volumes were 3.0 Bcf/day. If no gas existed in the Delta and only 2.0 Bcf/day were available from Prudhoe, the viability of the project would be seriously pre- judiced and the proposal to pipeline Alaska gas instead across Alaska, for liquefaction at a south-eastern Alaskan port and then move it by tanker to the California markets, would be greatly enhanced.

DR. WARREN: Ir. your talk you made the tacit assumption that to make a viable economic enterprise of the proposed gas pipeline to the Mackenzie Delta area, it is also necessary to transport American gas from the Prudhoe field and to feed both U.S. and Canadian gas to the no

Canadian market and the unlimited U.S. market.

On what basis is this assumption made? Is a Canadian pipeline feeding the Canadian market not a viable enterprise at present if the U.S. decides to ship Prudhoe gas directly to U.S.A.?

MR. HORTE: Pi Canadian pipeline from the Delta feeding the Canadian market only is not, at present, a viable scheme. The Canadian deficiencies forecast in the late seventies and eighties, while significant in terms of Canadian demands, are not large in terms of the volumes necessary to provide reasonable transportation economics. The deficiencies in Canadian demand grow at the rate of about 250 million/day annually and, unfortunately, demand cannot be saved up until it reaches large enough volumes to support a project of this magnitude. The market either is served by some alternative form of domestic or imported energy or it goes short. The only near-term alternate would appear to be imported- energy which in a condition of world-wide shortage might be very difficult even if it were considered desirable. Shortages, of course, would have even more dire consequences for the Canadian economy.

An anonymous questioner asked Mr. Warne (who presented Dr. Govier's paper): Are there any other products in addition to crude oil which may be derived from the oil sands? MR. WARNE; There are a number of additional constitutents in the oil sands which may have commercial value. One of the principal such ccn- stitutents is vanadium and considerable work has been done, particularly by one of the major oil companies, to determine the economic feasibility of recovering this metal. This work has been encouraging and there is some basis for optimism that considerable amounts of the metal will be recovered from the sands.

Another significant product is sulphur. The bitumen contains up to about 5% by weight of sulphur and a major part of this is recovered. Unfortunately, there is presently a dearth of markets for sulphur and the price is too low to make shipment from .ithabasca economic. In these circumstances, the sulphur recovered is stockpiled pending an improvement in sulphur prices.

The same questioner also asked:

Should development of the oil sands be deferred until production from them is required for Canadian markets? Ill

MR. WARNE;

Canada imports substantial amounts of crude oil into Eastern Canada while exporting about equivalent quantitites from Western Canada to nearby areas of the United States. It is only in the last couple of years that such exports from Western Canada have slightly exceeded imports to Eastern Canada. Canada therefore has not been a significant net exporter of crude oil. In addition, production from Western Canada is approaching capacity and in the absence of major new discoveries will decline to perhaps as little as half the peak capacity by 1985. Projects initiated in the oil sands now, in addition to providing supplementary production capacity, will accelerate the development of the technology of such production thus ensuring that production will be available later when required.

DR. D.C. DOWNING (Gulf Oil Research Centre) of Mr. Coates: You identified a few billion tons of Canadian coal which you considered to be available fairly readily and 86 billion tons not available. What are the main difficulties and problems in extracting this latter quantity? MR. COATES;

The Geological Survey of Canada have estimated that in-place geological reserve of low- and medium-volatile bituminous coal in the mountain regions of B.C. and Alberta to be 86 billion tons. Very little of this can be regarded as recoverable because of the following adverse characteristics of the deposits:

. severely disturbed geologically, with extensive folding, faulting, discontinuity, erosion, and irregularity of seam thickness; . much of the coal occurs in very steeply dipping formations (dips of 70 degrees to 90 degrees are not uncommon); conventional underground mining methods cannot successfully be applied to such conditions;

. much of the coal lies under deep cover, with weak roof conditions; . not all of the coal is of commercial quality; . much of the region presents access problems because of rugged topography and elevation; . some of the coal occurs in designated parks or wilderness areas in which mining has been banned. 113

SESSION II

ENERGY MARKETS AND THEIR DEPENDENCE ON PRICE

Monday, 15 October, 1973, p.m.

Chai rman REAL BOUCHER Directeur general de 1'energie Ministire des richesses naturelles Province de Quebec 114

TABLE I

World Energy Consumption Million Metric Tons of Coal Equivalent

Developed Developing Centrally World Countries Countries Planned Economies

1961 4,192 2,654 313 1,224

1962 4,418 2,794 337 1,286

1963 4,717 2,978 354 1,385

1964 4,978 3,126 371 1,481

1965 5,214 3,270 399 1,546

1966 5,507 3,438 427 1,642

1967 5,608 3,565 449 1,595

1968 6,019 3,797 489 1,733

1969 6,413 4,043 523 1,847

1970 6,843 4,300 569 1,974

% annual rate of growth 5.6% 5.5% 6.9% 5.5%

Source: World Energy Supplies 1961-1970 United Nations Statistical Papers Series J No. 15 ST/STAT/SER. J/15 table 1, page 7.

1. Excludes bunkers

In this table, conversion into coal equivalent is done on the basis of the heat energy that can be obtained from the fuels under ideal conditions. Thus hydroelectric power is equated to the coal that can generate an equal amount of heat. In some presentations, the coal required in a typical thermal station to generate the same amount of electricity is used as the equivalent of hydro or nuclear power. In the latter approach, hydro power has a coal equivalent some four and a half times higher than in the U.K. approach. 115

THE LONGER TEEM OUTLOOK FOR OIL

J.H. DAGHER

BP Canada Limited

WORLD ENERGY SUPPLY - DEMAND BALANCE

During the period 1961 to 1970 total world energy consumption was as in Table 1.

The developed countries with less than 307o of world population accounted for some 63% of total annual consumption throughout this period. North America, with some 6% of total world population accoanted for 357= of total consumption in 1961 and for 337o in 1970, that is a slight decrease in the share of total usage but still a disproportionately large share. On a per capita basis, the intensity of consumption in North America was even more pronounced . (Table 2).

The developing countries increased their consumption per capita at a higher than world average rate. However, mainly due to the impact of Japan, the developed countries as a whole increased their consumption per capita at an evan higher rate. The North American rate of increase in per capita energy usage was a healthy 3.6% per annum.

It is evident from the above that any forecast of future requirements must be highly dependent on the underlying assumptions as to growth (or decline) rates in per capita consumption. Were all the world to consume energy at North American per capita rates, a sixfold increase in energy supplies would be needed. This is of course completely outside the realm of financial and technical feasibility over a short period of time. Never- theless the wide range of uncertainty surrounding future economic growth in developing countries greatly adds to the uncertainty of any forecast of energy demand.

The contribution of the various forms of primary energy to the total supply is shown in Tables 3 and 4.

The decline in the share of coals and the .pid increase in the shares of crude oil and natural gas to the total energy supply is a reflection of the relative competitiveness of the fuels (including the convenience aspect) . The developed countries accounted throughout for around 50% of coal production and the centrally planned economies for around 40%. These are the areas where the labour intensive aspect of coal production was having thestrongest impact on the relative competitiveness of this source of energy. 116

TABLE 2

Energy Consumption per capita Kilograms Coal Equivalent per capita

World Developed Developing Centrally North Countries Countries Planned Economies America

1961 1,387 4,029 231 1,220 8,068

1962 1,433 4,188 241 1,260 8,288

1963 1,499 4,408 247 1,334 8,628

1964 1,550 4,572 252 1,403 8,927

1965 1,592 4,728 264 1,442 9,219

1966 1,649 4,920 276 1,507 9,640

1967 1,648 5,052 282 1,442 9,881

1968 1,734 5,335 299 1,542 10,398

1969 1,811 5,620 311 1,618 10,824

1970 1,897 5,914 330 1,704 11,128

°L annual rate of growth 3.6% 4.3% 4.1% 3.5% 3.6%

Source: World Energy Supplies 1961-1970 United Nations Statistical Papers Series J No. 15 ST/STAT/SER.j/15 Table 1 page 7 and table 2 page 25.

1. North America also included in column 2, 117

It is also significant that well over half the natural gas was produced (and consumed) in the U.S. Over the decade, the consumption mix in the U.S. shows a relative tread away from solid fuels and even liquid fuels in favour of natural gas. At the beginning and the end of the period the contribution of the various forms of energy to U.S. primary energy consumption were as follows:

Per cent of total 1970 1961

Coal and Lignite 19.1% 23.2% Crude Petroleum 40.2% 41.6% Natural Gas 36.4% 31.6% Other 4.3% 3.6%

100.0% 100.0%

Source: U.S. Bureau of Mines

In particular, with its vast coal resources, the U.S. has not incraased its consumption of this fuel proportionately with the growth of other fuels. The position, of natural gas compared to the rest of the world is particularly noteworthy: the rapid increase in consumption has resulted in a decline in U.S. gas reserves from 21 years' supply in 1961 to 13 years in 1970 and less than 12 years currently,

THE ENERGY CRISIS

From the foregoing, it is obvious that any view on future world energy supply patterns must have at its core a view of future U.S. energy demand and supply patterns. In particular, the U.S. is generally depicted as having an energy crisis. Is there a U.S. energy crisis and if so, are its causes such that it is only a matter of time before it becomes manifest elsewhere in the ;world? Or is it a crisis brought about by circumstances particular to the U.S. which the U.S. can solve internally and thereby prevent its -spread? Most importantly is it a short term or a long term crisis? In order to answer these questions a historical retrospective is helpful. •

One of the tnost important economic characteristics of oil production is that;it is very expensive to discover but once discovered, generally relatively, cheap to produce (in terms of physical production costs that is .excluding royalties and taxes).

• This characteristic is reinforced in the subsequent downstrfesm operations that bring crude oil to the consumer .in a usable form. Average variable costs thus are appreciably smaller than average total costs. Economic theory says that.in the short term firms in a competitive industry 118

TABLE 3

World Energy Production Million Metric Tons Coal Equivalent

Total Coal and Crude Natural Hydro/Nuclear Lignite Petroleum Gas Electricity

1961 4,270 2,022 1,486 671 91 1962 4,511 2,077 1,612 732 97 1963 4,788 2,160 1,728 798 102 1964 5,081 2,238 1,867 869 107 1965 5,316 2,268 2,001 930 118 1966 5,621 2,310 2,172 1,012 128 1967 5,756 2,205 2,329 1,090 132 1968 6,140 2,274 2,542 1,186 138 1969 6,514 2,332 2,735 1,299 149 1970 7,001 2,409 3,004 1,431 157

% annual rate of growth 5.6% 2.0% 8.1% 8.8% 6.2%

Source: World Energy Supplies 1961-1970 United Nations Statistical Papers Series J No. 15 ST/STAT/SER.J/15 Table 1 page 6 and Table 2 page 25.

TABLE 4

World - Proportion of Primary Energy Supplied by various sources

Coal and Crude Petroleum Natural Hydro/Nuclear Total Lignite Per cent of total Gas Electricity

1961 100 47.4 34.8 15.7 2.1 1962 100 45.9 35.7 16.2 2.2 1963 100 45.1 36.1 16.7 2.1 1964 100 44.0 36.7 17.1 2.1 1965 100 42.7 32.6 17.5 2.2 1966 100 41.1 33.6 18.0 2.3 1967 100 38.3 40.5 18.9 2.3 1968 100 37.0 41.4 19.3 2.3 1969 100 35.8 42,0 19.9 2.3 1970 100 34.4 42.9 20.4 2.3 119

will remain in business for some time at less than equilibrium prices as long as price exceeds average variable costs . In the case of an oil deposit, the unspecified period of time could be equal *"o the time required to deplete the reservoir. That is, oil will continue . ••• produced, transported, refined and supplied to the consumer even A.._n prices are appreciably lower than the normal equilibrium price, that is the price which is equal to both the marginal cost and the average total cost. On the demand side, in the short term, demand is highly inelastic which means that very large variations in price are needed to place "surplus" oil. (It also means that large taxes can be levied without affecting volume too much). From the very early days of the industry, wide fluctuations in crude oil prices were a frequent phenomenon, more the rule than the exception. Reporting on price condition a hundred years ago in the Petrolia district of Southwestern Ontario the Canadian Monetary Times and Insurance ' ronicle stated "In 1862 oil was to be had for ten cents a barrel from the -lowing wells of Oil Springs and ... in 1865 it ran up to $10 per barrel...". The latter price is considerably higher than current prices in monetary value and much more so in real value.

Continuous and generally abortive attempts at stabilizing prices were made by Federal, State or Provincial Governments and by industry often with the blessing of and in close co-operation with Governments.

The first effective price stabilization system evolved in the U.S., during the Depression. The discovery of huge fields such as East Texas, Wilmington, Slaughter, Conroe West resulted in chaotic price conditions. Protectionism - in oil as well as other sectors of the economy - was prescribed as the antidote in those depression days. Accordingly, the 1930's saw the creation of a complex network of State and Federal regulations designed to achieve price stability by extending the definition of conservation from its accepted physical engineering interpretation to economic conservation. These regulations were repeatedly tested in State and Federal courts and after a long period of trial and error, a system was put in place which effectively curtailed production to market demand. The desired aim of stable prices was eventually achieved but only at the cost of raising average crude oil prices to a level sufficient to make it economical for marginal stripper wells to remain in operation. A 36° gravity Oklahoma- Kansas crude oil which had tumbled from $3.50 per barrel in 1920 to $0.69 in 1932 was gradually raised back to the $1.20 - $1.50 range in the late 1930's. This trend was reinforced during the war by a policy of encouraging the drilling of marginal and stripper wells at the expense of wildcats. By

1. A.W. Stonier and D.C. Hague. A Textbook of Economic Theory. London, Longmans, Green and Co. Ltd., 1959 pages 134-136.

2. Canadian Monetary Times and Insurance Chronicle, Vol. 1, No.2, Aug. 29, 1867, p.3.

3. API Facts & Figures, 1959, p. 374. 120

1944, maximum efficient rates of production were being reached in most major producing States and for some months in 1945, were in fact exceeded. With the lifting of controls on demand at the end of the war, crude, oil prices rose to the $2.50 - $3.00 level in the late; 1940's. The protectionism of the 1930's gave way to a policy of encouraging imports of crude oil for the prevalent opinion was then that the U.S. was running out of crude oil. This liberal climate on crude oil imports gave rise in the early 1950's to an unprecedented rush by U.S. companies to explore in Canada, Venezuela, the Middle East. Their success was such that within a very short time U.S. crude oil imports caoie to represent a significant proportion of domestic production. (10% in 1954, 127= in 1955, 14% in 1957). U.S. domestic producers and royalty owners began to press for controls on imports which became embodied in the 1955 National Defence Amendment to the Trade Agree- ments Extension Act providing for limits to be placed on the imports of any strategic item which in the opinion of the President, upon advice from the Office of Defence Mobilization, was being imported to an extent which threatened to jeopardize national security. After attempting - unsuccessful- ly - to institute voluntary controls, in March 1959 the U.S. Administration instituted mandatory controls on crude oil and product imports.

Before pursuing the effect on the U.S. of this U.S. measure, its effect on the world scene was to create a large surplus of crude oil in Canada, Venezuela and the Middle East. Many U.S. companies having looked for and found oil with the intention of taking it into their U.S.refineries were then unable to do so. Naturally they chose to enter European and other markets rather than leave their oil in the ground. This led to severe price cutting on products which soon had to be followed by reductions in crude oil prices.

Reverting to the U.S. scene, broadly the import control system tied the offshore crude oil imports East of the Rockies to a level equal to 12.2% of anticipated production of domestic crude and natural gas liquids while West of the Rockies imports were allowed in volumes sufficient to bridge the gap between domestic supply and demand. Product imports, except for heavy fuel oils, were limited to historical levels.

How the quotas were allocated among various companies is irrelevant here. Suffice it to say that through most of the period it •esulted in a bonus of approximately $1.25 per barrel of import rights to the recipient, giving an indication of the price advantage of foreign crude oils relative to U.S. crude oils.

The system worked - with much 'ad hoc-ing'- throughout the 1960's and it worked essentially for one reason, namely that there was sufficient existing and new productive capacity to increase domestic production so that

1. U.S. Cabinet Task Force Report on Oil Import Control, February 1970. 121

the 12.2% import limit would not be binding. U.S. domestic crude oil and lease condensate production rose steadily till 1970 when it reached 9,637,000 barrels per day, but then in 1971 dropped to 9,463,000 barrels per day with a further slight drop to 9,451,000 barrels per day in 1972.* (These figures exclude of course Alaskan potential). Once it became clear that U.S. domestic production could not increase a-pace with demand, it was evident that the fixed import proportion could not bridge the supply/ demand gap. While it was obvious that a change in the U.S. control system was inevitable, there were no indications whatsoever or perhaps even worse, there were many conflicting indications as to the form the new system would take. A Cabinet Task Force was created on March 25, 1969 to conduct a comprehensive review of oil import restrictions. It submitted its report in February 1970 with the following general recommendations.^

"General plan. A majority of the Task Force recommends that the President proclaim in early 1970 a phased transition to a tariff system for controlling imports, to take initial effect no later than January 1, 1971, with the following principal features: (1) initial imposition of an increased tariff on non-preferred crude oil at a level $1.35 per barrel above existing tariffs; (2) phase-out of special quota privileges over a three-year transition period by means of a "tariff-free" quota; (3) deferment of decision on further tariff liberalization until January 1972, at which time the program managers may continue the process of liberalization if they are then persuaded on the basis of the best available evidence that indicated reserves in North American frontier areas will be sufficient to meet the aggregate 1980 production estimates set forth herein, or until January 1973 or January 1974 if the program managers are so persuaded by then; (4) a comprehensive review of the program no later than 1975, including an in-depth study of the post-1980 situation, to determine whether it then appears consistent with the national security to continue - or, if need be. arrest or reverse - the process of tariff liberalization."

Some key members of the Task Force dissented with the analysis and conclusions of the Report particularly with the recommended tariff approach to controls. No fundamental decisions were taken on the basis of the report, Shortly after, the National Petroleum Council, an officially established

1. Oil and Gas Journal July 30, 1973, pages 69-73. (Excludes N.G.L.)

2. U.S. Cabinet Task Force Report on Oil Import Control, February 1970, pages 136-137. 122

industry advisory board to the Secretary of the Interior was asked to undertake a comprehensive study of the U.S. energy outlook. They presented their report in December 1972. which recommended, among other things, the continuation of a mandatory import control programme. Meanwhile, equation of supply and demand continued to be achieved through temporary stop-gap measures such as allowing special imports of heating oils or allowing refiners to "borrow" against future quotas and special allocations.

The overall uncertainty as to the futurp direction of U.S. energy policy meant that the necessary investment was not forthcoming in U.?.. domestic refineries, in deep river ports, in offshore refineries (with some notable exceptions) in ships, in pipelines, in offshore producing capacity and generally in the whole massive structure that would eventually be needed to meet the rising demand. Several complicating factors added to the uncertainty and prevented the commitment or expenditure of the necessary monies while other unexpected factors added to the oil and gas supply stringency. Among these may be mentioned:

i) Ecological preoccupation which resulted in regulations and actions that prevented or considerably delayed the construction of refineries, nuclear and thermal power plants, pipelines, (Alaska being the prime case in point) deep river ports etc.

ii) Lag in the nuclear power plant construction program due to technological problems , delays in delivery of equipment - in addition to ecological delays.

iii) Unexpected surge in demand due to switches in power generation from coal to oil or gas, to the higher specific consumption of new cars, and to rapid economic expansion.

iv) Uncertainty as to new car emission control regulations - since altered or postponed on two major occasions - and which could have pre-empted a sizeable proportion of funds which would otherwise have been available to industry for expansion.

v) Turmoil in the international monetary scene which, among other things, was reflected in offshore crude oil prices.

vi) Mounting power or effectiveness of OPEC in securing higher per barrel revenues to member Governments and all the associated threats that were voiced and m some cases implemented (nationalization/expropriation) in the process.

1. National Petroleum Council's Committee on U.S. Energy Outlook Report, December 1972.

2. Id. page 320. 123

The debate was naturally broadened to all other forms of energy, with natural gas attracting particular attention regarding the desirability and efficacity of decontrolling prices, which in interstate commerce have been under FPC control since 1954. Many experts have attributed the spectacular rise in the share of natural gas in the total U.S. energy scene - and the resultant decline in U.S. proven reserves of natural gas - to underpricing imposed under FPC controls. In many major energy consuming centers the city gate price for natural gas was considerably lower than the equivalent btu price of hfiavy fuel oil. The same applies to Canada albeit to a lesser extent .

Meanwhile, and as a result of the foregoing, acute energy shortages began to be experienced in certain areas of the U.S.

Accordingly, President Nixon took two large measures. The first, an interim one taken on January 17, 1973, raised considerably the ceiling on 1973 crude oil and products import quotas and suspended import quotas on heating oils to April 30, 1973. The second, more far reaching was promulgated on April 18, 1973 in conjunction with a White House "Energy Message" to Congress.'- This virtually abandoned the old quota system and substituted instead a gradually rising fee on imports of crude oil and products above a predetermined level. It also introduced a strong incentive in favour of domestic refining relative to offshore refining. Other far reaching but longer term measures were also enunciated in the Energy Message.

The lifting of controls on crude oil and product imports found the U.S. and the world oil industry largely unprepared to cope with this unexpected and far reaching change. For the reasons previously mentioned, the refining capacity in the U.S. or elsewhere, the deep water ports, the ships and indeed the offshore crude oil productive capacity had not been built ready to be used when - and if - this unexpected radical change in U.S. policy was made, nor would it have been prudent to do so.

The ensuing rush by U.S. oil companies to mop up available crude oil, products available in world refineries and the ships to carry these has resulted in unprecedented high spot prices for crude oil, products and ships.

In October 1972, furnace fuel heating oils could be imported into the Worth American Eastern Seaboeidfrom Caribbean refineries at around 14c per gallon. In May 1973 c >oted prices for products at these export refineries and spot freight rates were anywhere from 25C to 28

Department of Energy, Mines and Resources. An Energy Policy for Canada - Phase 1, voluine 1, page 113. The White House, Message to Congress and Proclamation Modifying Proclama- tion 3279 Relating to Imports of Petroleum and Petroleum Products. Office of the White House Press Secretary April 18, 1973. U.S. Department of Interior "World Wide Crude Oil Prices - Second Report" Technical Report P3-6-72. June 1972. 124

barrel, thus more Chan doubling the cost of importing a barrel of Middle East crude into the U.S.

The effects, spread throughout the world. Cargo prices at Rotterdam over the span of six months changed as follows:-

January 1973 July 1973 $ per metric ton

Regular gasoline 42 99 Heating oil 36 63 Heavy fuel oil low sulphur 24 28 Heavy fuel oil high sulphur 16 18

Note the little change in heavy fuel oil prices which were exempt from import controls even before the lifting of import controls on all oils.

Canada reacted, first in February 1973 by controlling the export of indigenous crude oil after more than a decade when the aim had been to press the U.S. into allowing increasing quantities of Canadian crude oil exports, and then, in June 1973 by extending controls to the exportation of gasolines and heating oils whether derived from domestic or imported crudes.

THE LONGER TERM OUTLOOK FOR OIL

The worldwide rise in prices and the scramble for security of supplies to domestic markets have been interpreted as evidence of an energy crisis and, with less justification, of its enduring nature. It was precisely because products and crude oils could not be imported freely into the U.S. in 1972 that their prices and particularly freight costs were low a year ago and it is for the opposite reason that they are now high.

This is not to suggest that the rise in crude oil and product prices is entirely the result of this sudden - and in that sense temporary - tightness or that other sudden tight conditions will not again recur after the current one has been resolved. But the longer term outlook can only be taken after eliminating the transient effects of the current situation.

Having removed from today's picture, the abnormal elements (tightness of production facilities, of tankers capacity, of pipelines, of deep water facilities, of refining capacity, of storage tanks) brought about mainly by the sudden change in U.S. policy the resulting steady state picture is broadly as follows:

1. PLatt's Oilgram - dated July 27, 1973. 125

On January 1, 1971, total world proven recoverable crude oil reserves amounted to 552 billion barrels. In 1971, total world crude oil production amounted to 17,6 billion barrels so that existing known reserves were sufficient to provide 31.4 times the yearly demand. Were the demand for oil in the 1970's to grow at the same rate as it did in the 1960 's total world cumulative demand for oil during the decade of the 1970's would amount to some 238 billion barrels. Thus even if no oil at all is discovered, there are ample known reserves of conventional crude oil to meet the demand for the decade leaving at the end of it some 314 billion barrels, equal to eight years' supply of the thai current demand rate. But of course new oil will continue to be discovered. Over the last ten years or so, gross additions to world proven reserves of crude oil averaged some 35 billion barrels per year.

In fact, were the 1970's to repeat the performance of the 1960's as far as growth in demand (at 8.1% per annum) and of reserves additions 'at 35 billion barrels per annum) then more oil should be discovered in the decade than will be consumed.

However, were we to assume the continuation of recent growth rates, then early in the 1980's demand will begin to exceed historical rates of gross reserve additions. Of course such a situation is not tenable for long and either demand will have to fall short of purely geometrical growth or reserve additions will have to grow at a higher rate. More likely, both phenomena will occur to varying degrees induced partly by purely economic forces (interfuel competition, price elasticity of demand, of supply) but also, by deliberate Government policies: on the consuming countries' side by forced diversifications of energy sources, greater recourse to more abundant indigenous and therefore more secure, even if temporarily more expensive, sources of energy, and on the producing countries' side by anticipatory conservation.

On the demand side, the main factors that are expected to contribute to a reduction in the growth of oil consumption are:

1) Resurgence in the competitiveness of coal. As indicated in the table 4 in the 1960's the growth in crude oil and natural gas production

1. DeRolyer & MacNaughton Twentieth Century Petroleum Statistics, 1972 page 1

2. World crude oil production in the current decade has been 16.7 billion barrels in 1970, 17.6 billion barrels in 1971, 18.6 billion barrels in 1972 and is estimated at 20.4 billion barrels for 1973 giving a growth rate of 6.6% per annum in the 1970's so far. 126

considerably exceeded growth in energy demand. Part of this increase was at the expense of coal and a pure substitution - railroads, thermal generation, heating - and to that extent there is a once and for all component in oil's growth in the 1960's. Also, this substantial gain in oil's share of world energy supply was achieved under conditions of excess world crude oil productive capacity and the attendant pricing characteristics tc which reference has been made previously. The rise in crude oil costs that has been taking place since the fall of 1970 - after the steady decline of the 1960's - is gradually restoring coal's competitive position. In North America coal already has the largest share of thermal power generation followed by natural gas. If wellhead prices of natural gas are allowed to rise, the substitution will be towards coal rather than oil, on the basis of current relative prices. A similar trend to coal may also be expected in Europe and Japan where oil accounts for a significant proportion of thermally generated electricity. In the synthetic gas market coal is also expected to be the preferred raw material on the basis of price and availability even if in the interim liquid feedstocks will likely be the main source of SNG.

2) Security of supplies and balance of payment considerations will also contribute to coal's resurgence. Unlike oil, coal is mainly found and produced in developed countries or in centrally planned economies. During the 1950's and the 1960's, many Governments, against the then current expectation of unlimited and steadily cheaper oil, had adopted policies designed to reduce or phase out domestic coal production. In the current changed circumstances a reversal of such policies is to be expected and is in fact taking place. In addition to direct assistance to coal a considerable measure of indirect and potentially more fruit- ful assistance is being given through more intensive research in coal gasification, liquefaction,transportation, desulphurization.

3) The foregoing applies also to nuclear energy. In Canada there is currently 2,000 megawatts electrical nuclear power capacity and a further 4,100 megawatts are under construction or committed. The energy study papers recently published by the Department of Energy, Mines and Resources foresee this growing to 15,000 megawatts by 1980, 30,000 megawatts by 1990 and by the year 2000 to about 100,000 megawatts. From its present position of supplying 0.571, of all electric power generated (and 2% of thermal power) nuclear energy is expected to account for-^"/,, of all electric power (and 63% of thermal power) by the year 2000. The extent to which electric power, generated mainly from non-oil sources can substitute for oil uses will vary from one sector to another. In the residential sector, where heating is by far the

1. Department of Energy, Mines and Resources. An Energy Policy for Canada Phase 1 - Volume II page 299.

2. Id. page 292. 127

major end use for oil, the peak appears to have been reached in oil consumption. Future increases in residential energy consumption will be provided by gas and electricity. In the commercial and the industrial sectors, oil usage is expected to increase but at a much lower rate than total energy consumption. Over the next two or three decades only the transportation sector will derive most of its additional energy requirements from oil.

';) The rise of energy costs will result in an improved efficiency of energy utilisation. Here the scope of conservation is vast indeed. Over one third of the energy consumed in the developed countries is used in the process of converting primary fuels into other more convenient forms of energy and in the transportation of energy. A large proportion of the remainder, that is the energy delivered to consumers in the form they have chosen to buy it could be economized but it is difficult to apply the term waste to the whole of this proportion since it is largely a function of the subjective assessment of the researcher as to what is an adequate room temperature, which trip should be taken by car rather than by bus etc., whether a small foreign imported car should substitute for a large North American car etc. While the former, objective, set of sources of waste is largely under the control of engineers the latter is largely a matter of personal choice by millions of individuals. But personal preferences can be altered without coercion (unless taxation is a form of coercion?). For example, in the transportation sector, the energy requirements of various modes of transportation are as follows ^:-

BTU per passenger mile Intercity Passenger Traffic

Bus 1 ,090 Train 1 ,700 Car 4 ,250 Aircraft 9 ,700 Urban Passenger Traffic Bus 1 ,240 Gar 5 ,060

1. Department of Energy, Mines and Resources. An Energy Policy for Canada Phase 1 - Volume II page 8.

2. Petroleum Press Service July 1973 page 258. 123

BTU per Ton Mile

Intercity Freight Traffic Pipeline 450 Waterway 540 Train 680 Truck 2,340 Aircraft 37,000

The main areas where significant reductions in energy usage can be achieved are:

i) In the residential/commercial field through better insulation of existing homes and buildings, higher insulation standards for new construction, minimum efficiency standards for appliances, furnaces, air conditioners, through smoothing of daily and seasonal cycle of demand, through education in conservation etc.

ii)In the transportation sector through improved mass transit, improved energy efficiency of automobiles, new freight hand1ing sys terns.

iii)In the industrial sector through greater use of recycling and secondary use of waste heat, smoothing of daily and seasonal cycle of demand, relocation of certain industrial activities on a national or even international scale. It has been estimated that U.S. crude oil consumption in 1990 could be reduced from a normal level of 27.5 million barrels per day to a level of 20 million barrels per day through the workings of the aforementioned conservation measures . The use of waste heat from power station and large industrial complexes, the generation of power from domestic waste and from agricultural waste are cases in point where a start has already been made.

Many of these savings or new form of energy generations are and will increasingly take place through the normal operation of the cost/benefit principle in a free economy thnt is, their contribution will very largely be determined by energy prices and cannot therefore be forecast a priori as purely engineering questions.

5) Working in the opposite direction, a greater demand for energy will result from the increased awareness for environmental protection. The standards which a society sets for itself regarding the quality of its environment have a significant effect on the energy it consumes both as to its quantity and as to its unit cost. This is far too large and complex a subject to be treated in any degree of detail. Only summary results need be mentioned:

1. Vogely Dr.W.A. ''Characteristics of the Denand for Oil and Gas" in International Inc., seminar on The Oil and Gas Shortage. 129

1) The Department of Energy, Mines and Resources has done a thorough analysis of the impact of environmental control measures on each of the major energy sources and has estimated the resulting cost increase at 5 to 7 per cent of total energy costs over the next decade. o it. The U.S. National Petroleum Council has estimated che additional costs at between 4 and 5% of total costs.

These cost estimates do not bring out other important aspects of environmental protection, namely their effect on the balance of payments and on security of supplies. To the extent that they result in a shift away from indigenous sources of energy both of these aspects are adversely affected by tighter environmental norms.

On the supply side, the main factov.3 that are expected to contribute to increasing the availability of hydrocarbon fuels are:

1) Revision and extension of proven reserves in existing production areas. Proven crude oil reserves are generally defined as the volumes that can be demonstrated by geological and engineering data to be recoverable with reasonable certainty under existing economic and operating conditions. As economic parameters change proven reserves may be enlarged through improved recovery techniques. The U.S. National Petroleum Ccuncil anticipates that average recovery efficiency will rise from 31% of oil-in-place in 1970 to 37% in 19S5, with new reservoirs achieving an efficiency of close to 50%. Also, the "proving" of reserves obeys a sort of law of supply-and-demand, whereby potential reserves are not "proven" in the rigorous sense, until the need for it arises.

2) New frontier areas like Canada's arctic regions, Siberia and offshore areas generally, are becoming economically attractive as exploration ventures with the rise in crude oil prices and with improvements in technology. The North Sea is a case in point. A recent report to the U.N. Committee on Peaceful Uses of the Sea Bed places the estimate of recoverable .tude oil in offshore areas

1. Department of Energy, Mines and Resources. An Energy Policy for Canada Phase 1, Vol. I - Analysis page 27u.

2. National Petroleum Council Op. Cit page 53.

3. National Fetroleum Council Op. Cit page 310. 130

to 1,000 meter depth, at 2.3 trillion barrels (plus an equivalent amount of natural gas) which is some 4 times current remaining proven recoverable crude oil reserves.1 The report expects that techniques for well completion at these depths will have been developed by 1980 so that these potential reserves could come into production during the 1980's to an extent that will be determined primarily but not exclusively by prevailing and anticipated crude oil prices. For Canadian frontier areas, the response ol the supply of oil anJ gas to price has been analysed in great detail in the EMR energy papers. The analysis indicates that at a delivered cost of $6 (in 1972 $) per barrel a large exportable surplus of oil would be available (from existing reserves, frontier areas and synthetic Athabasca and heavy crude oil deposits) until the first uecade of the next centure.

3) Synthetic oil production from Tar Sands, Heavy Oil deposits, Shale Oils is rapidly nearing economic feasibility. Already, current crude oil prices support the economics of developing selected areas of the Athabasca Tar Sands. It is estimated that at $6 (in 1972$) per barrel, some 35 billion barrels of oil (three times current Canadian reserves) would be economically recoverable by open-pit mining techniques . If research now underway on in-situ recovery of Athabasca Tar and other boavy oils deposits is successful, substantial additional quantities of oil would be economically recoverable at the $5-$7 (in 1972$) per barrel price range. 3 A similar price level would also make it economical to produce some 54 billion barrels of synthetic crude from Colorado Shales .4 Vast deposits of heavy oils and shales are also known to exist in Venezuela, Brazil, China and other parts of the world.

4) Coal liquefaction is expected to become economically attractive at crude oil prices in the range of $5-$7 a barrel 5 , not a very large increase from the present $4 per barrel. When that stage is reached, the demand for crude oil will be further reduced by a more intensive upgrading of the barrel and vacating some of the current heating usages of oil. There are many technological problems to be resolved and possibilities to be exploited before a significant substitution of coal for oil is achieved but these are increasingly being explored with support of Government sponsored research.

1. Oil and Gas Journal July 30,1973 "Newsletter" pages 1, 2.

2. Dept. of Energy,Mines and Resources Op. Cit page 96.

3. Dept. of Energy.Mines and Resources Op. Cit Vol. II, pages 73-74.

4. Nat. Petrol. Council Op. Cit page 206.

5. Dept. of Energy, Mines and Resources Op. Cit Vol. I - Analysis page 69. 131

CONCLUDING REMARKS

The above enumeration of the factors that will eventually bring into equation the supply and demand for oil did not touch upon the problems that may arise in the process. Ex-post, of course, supply will have been equal to demand and at any given moment in time demand and supply match either in a stable equilibrium or otherwise (excess supply, unfilled excess demand, rationing etc.). The real questions therefore are how will rhat equation obtain, how it will unfold through time and how it will affect the other "equations" in the world's economies.

What greatly complicates any prognostications in this domain is that energy is often one of the major preoccupations of Governments, the subject of policies which create "large" options, the selection of one of which, rather than another, can have a widely different impact on the economy and the selection is not always entirely a matter of economic choice in the narrow sense.

This is abundantly illustrated by the various options for Canada considered in the recent EMR energy papers and which were explored with the CANDIDE econometric model. Depending on the political choice of on^ of the options or die other, GNF could grow over the remainder of the decade at anything between 4.6% per annum and 6.4% per annum in real tei-ms , inflation could range from 2.3 to 5.2% per annum, unemployment from an average of 2.7% to an average of 5.5%, disposable personal income (in 1961$) could grow at rates varying between 4.5% and 7.8/J..1 Admittedly this options' analysis is theoretical, designed precisely to bring out the consequences of each of the theoretical options so as to provide a basis for choice. Nevertheless, there is no clear cut indication, on the basis of these results, that the political choice will inevitably rest on one particular option. Added to which, each option has inherent uncertainties which only time will resolve.

The same wide variety of options exists on a world scale. There- fore while the natural and technological resources exist to enable the world community to progress gradually to the new energy era of more diversified and esoteric forms many forces may intervene to make the progression somewhat chaotic. Foremost among these are:

1) Financial limitations. In a recent forecast the Chase Manhattan Banic estimated that the oil industry (outside centrally planned economies) will need to invest a total of $1 million-million between now and 1985 in order to meet expected demand, of which, on the basis of recent historical trends, some $400 billion would have to be secured

1. Dept, of Energy, Mines and Resources Op. Cit Vol. II page 199. 132

from the capital markets of the world in competition with all other segments. This is largely a historical extrapolation and to that extent may not be a valid picture of the future but it is indicative of the magnitudes involved. It is noteworthy that all other energy alternatives to conventional oil and gas are characterized by often larger "unit project costs" and long lead times.

2) Investment choices of producing countries. An increasingly larger proportion of a higher priced crude oil is accruing to producing countries. Various investment opportunities will compete with investment in oil production according to the choices open to the recipient country. A diversion of energy funds into other avenues may therefore take place which may further add to the financial strains on the energy industries.

3) Political problems causing interruption of supplies, bilateral "every-man-for-himself" arrangements, scramble for resources, enforced cut-backs and over cautious anticipatory conservation on the part of producing countries, international trade; balance of payments and other world monetary problems.

4) Ecological delays and unexpected technological problems which may delay the coming on stream of alternative forms of energy.

All these are SJ many problems that may have to be surmounted over the next three or four decades on the inevitable and necessary path towards a new world energy balance where oil energy will play a still substantial role. 133

ENERGY MARKETS AND THEIR DEPENDENCE ON PRICE ; GAS MARKETS

ROLFE R. COLPITTS

Lalonde, Girouard, Letendre & Associates Consulting Engineers

PREFACE

s-or the last forty years, North America in general has enjoyed very low energy costs, as compared to many industrialized areas of the world.

Having now substantially committed our low cost energy resources, we face the prospect of increasing costs for a new supply, more in line with costs in Europe and Japan.

At the same time, a new consciousness of pollution hazards has arrived which will result in further increases in energy costs, but there is as yet no international solution to a global problem. The real results of the Conference on the Human Environment in Stockholm are unknown as yet, since to be successful, a reduction of na- tionalistic feelings would be necessary. It is obvious that the United Nations is our only existing agency which could be equipped to handle the world-wide problem. Briefly, there are no prospects for a true energy shortage in Canada over the next 5 years. Events in the United States will certainly affect distribution and costs. There are energy supply problems after 1978. There is a shortage of energy which is environmentally acceptable. Natural gas has become valuable as a means of controlling air quality, and the "normal" * price of natural gas can be expected to rise

"Normal" means a situation of no major armed conflicts and no shutdown of supply by oil exporting nations. 134

NATURAL GAS RESERVES AND PRODUCTION 1963 - 1984

so ALBERTA

MARKETABLE RESERVES

MARKETABLE PRODUCTION

S3 64 69 66 67 66 60 70 7t 72 73 74 73 76 77 T8 79 80 81 82 83

YEAR SOURCES SEE REFERENCES

Fig. I 135 about Si/million Bills in much of Canada by mid-1973 over 1969, with further increases taking place due to wellhead increases. TransCanada PipeLines will run into deiiverability problems by 1978-79 in Alberta, making Fron- tier Natural Gas a necessity.

The situation in the United States could be of great help to a Canadian manufacturer in the next five years, with temporary plant shut- downs in the U.S.A. due to energy shortages.

Appendix "A" contains a list of industrial processes where a supply of gas is advantageous or essential. However, gas must be available at competitive prices to that in other countries for the processes to be used.

It should be noted that Canada is the only Western industrialized nation with an adequate "above ground" energy supply on a net basis in the period of 1973-78.

NATURAL GAS SUPPLY

The Alberta Utilities have 30 years supply guaranteed to them by the Energy Resources Conservation Board.

Government policy Important policy decisions on natural gas seemingly are made every ten years. Iii 1959, the National Energy Board was formed to hear the first export application.

In 1969, a hearing started on the export applications of six different organizations. These hearings concluded in April 1970. The decision determined that Consolidated Natural Gas would not be allowed to export from Canada. Consolidated helped to raise field prices overnight by 3i(£/mcf in Alberta. The average annual increase otherwise was 0.25

Facilities to supply eastern Canada In 1Q67, a new supply of natural gas was made available through the Great Lakes Project to Eastern Canada. To make this project viable, the distributors signed contracts covering their increased requirements for 5-7 years.

The so-called "Great Lakes Gas" was sold out in 1971, since the Great Lakes project was two years late in being completed.

It has been obvious for some time that another major construction job would be in full swing in 1972-73, even neglecting the recent negotia- tions with Ontario Hydro for very large quantities of natural gas. This project will also be 18 months late in getting underway because of court actions. 136

Rates Since TransCanada's planning for previous project was done under conditions of much lower interest rates, it was obvious that they would need a rate increase by 1972 if they were to get a new major project off the ground. Accordingly, a rate hearing started or. February 9, 1971, before the National Energy Board which lasted about two years. The distributors also need a rate increase^for the same reasons enumerated above. Arctic Supply The attached Fig.l indicates that TransCanada PipeLines will need deliveries from the Arctic starting in 1978-79, in order to keep supplying their present customers. Arctic wellhead prices start at 32

From 1954 to 1964, expenditures by the oil and exploration and producing industry were substantially above the revenue from the production of oil and gas in Canada every year. In 1965, there was a marked reduction in expenditures which, for the first time, boosted revenues to the industry above expenditures in Canada. This is not to say that the Canadian oil and gas producing industry actually dropped overall expenditures, since their expenditures in areas such as the North Sea increased markedly. The reduction in expenditures by the producing industry below the revenue line in Canada led to a reduction in the footage drilled from 1965 to 1971, and in fact the 1971 footage totalled 33% below the 1965 total. Drilling footages have since increased to the point where all the available drilling rigs in Western Canada are being used. Expenditures by the producing industry in Canada in the period 1965-1969, although lower than their revenues, were only marginally lower. Since 1969, revenues have increased much faster than expenditures and in 1973, it is expected that revenues will be 40% higher than expenditures. The National Energy Board figures most recently published indicated a deficiency in reserves. The decision of the National Energy Board resulting from the Dome hearing should indicate the current reserve life ratios. 137

It is to be hoped that the present greater drilling program will result in a substantial addition to reserves, otherwise T-ansCanada Pipe- Lines will run into field delivery problems before they can hope to obtain a new gas supply from new areas. Between 1973 and 1978, TransCanada PipeLines will still be almost completely dependent on Alberta as a source of gas and although the reserves are there, it is quite possible that the "delivery" may not be available. In addition to this factor, the Alberta Government is presently refusing to grant more export permits as one way of negotiating with the Eastern consumers. In theory, natural gas found in the vicinity of Sable Island can be exploited by pipeline when the reserve total reaches about 5 trillion cu.ft. It can be exploited through the process of liquefaction at a much lower reserve figure. Westcoast Transmission- Westcoast Transmission presently has adequate reserves to meet their commitments (25-year life index), but are short on deliverability. Recently, they signed a contract with El Paso to export 450,000 mcf/day more natural gas. El Paso will provide exploration funds to prove up the additional reserves required. If the reserves are not forthcoming, the additional export will not be approved. Liquefied natural gas (Methane) The first ship designed to carry 300,000 bbl cargoes of liquefied natural gas (LNG) spot shipments commenced operation in mid-1971. Up to the present, all such ships were designed for specific runs such as: Algeria to Le Havre Algeria to London Libya to Barcelona Libya to Spezia Alaska to Japan Borneo to Japan Initially, the ship will supply peak shaving gas to New England, since the New England distributors cannot obtain new gas supplies at any price from North American sources. In the meantime, El Paso is organizing a project to deliver LNG in large volumes on the East Coast of North America by 1976. Similar projects could provide an opportunity for a "clean" fuel supply in the area East of Montreal. However, the overall cost of the gas after storage and regasifi- cation will be $1.00/mcf or more. The Federal Power Commission in a landmark decision recently ruled that new gas supply projects must be self-supporting, with new 138

customers paying for the new gas, etc.. Ttrs will effectively stop development, if allowed to stand, thus playing invo the hands of those who ad- vocate zero-growth. NATURAL GAS DEMAND AND PRICING There are two areas in Ontario where the demand for natural gas is almost unlimited. They are: The Windsor area and the Golden Horseshoe area, principally because of environmental rules. In Ontario, the sulphur limits really stem from a ground level concentration limit which prohibits high sulphur oiels from being used in areas which are thickly populated and highly industrialized. It is recognized that there are other considerations as regards basic cement manufacturing plants. The Task Force established by the Government of Ontario to look into future energy demand has indicated that the use of natural gas will increase 40% from 1970 to 1980 and the percentage of the total energy market will also increase. Residual fuel oil with sulphur contents in the range from 1% to 2% has been in long supply, and at a low price, mainly due to the fact that the New York and Boston areas have environmental rules, giving a maximum of .37% sulphur. These restrictions had to be lifted in February '73 for 45 days, in order to keep the two cities from running out of fuel, and as expected, President Nixon's energy message pointed the way to a partial relaxation of the extremely restrictive environmental rules in favor of employment. However, under present conditions, and assuming that Alberta is able to foist its gas pricing ideas off on the industry, it is obvious that TransCanada PipeLines may lose the industrial boiler fuel load within roughly 300 miles of Montreal. This will lead to a low utilization factor on the system east of Toronto to any grea\. extent because of the storage possibilities in Southwestern Ontario. During the fall of 1972, the Natural Resources Department of the Province of Quebec published a study of the objectives of a suitable energy policy for Quebec.

The following p.ages show two tables reprints from 'i.es Objectifs d'Une Poiitique Quebecoise de VEnergie" which indicates that Quebec would like to see gas consumption doubled in the period from 1975 to 1985, with the overall percentage of the total energy market rising from 4% in 1970 to 8% in 1980. The main reasons behind this effort is to create a competitive atmosphere and to provide gas service in areas which need industrial development. "LES OBJECTIFS D'UNE POLITIQUE QUEBECOISE DE L'ENERGIE" TABLEAU 12 Repartition de la consommation de gas nature! par secteur - 1963 - 1970

Domestique Industrie! Commercial Total Mi.p.c. % Mi.p.c. % Mi .p.c. % Mi .p.c. %

1963 7,455 27.1 17,675 64.3 2,358 8.6 27 ,488 100 1964 8,708 26.2 22,125 66.5 2,418 7.3 33 ,251 100 1965 9,753 31.2 18,768 59.9 2,793 8.9 33 ,314 100 1966 9,980 30.6 14,452 54.7 3,174 9.7 32 ,606 100 1967 10,141 28.7 20,265 57.2 4,977 14 .1 35 ,383 100 968 11,398 25.7 27,283 61.6 5,605 12 .7 44 ,286 100 1969 13,153 25.8 31,405 61.5 6,466 12 .7 51 ,024 100 1970 14,625 28.6 29,295 57.4 7,134 14 .0 51 ,054 100

Mi s million o

"LES OBJECTIFS D'UNE POLITIQUE QUEBECOISE DE L'ENERGIE TABLEAU 18 - Pr§visions de consommation d'gnergie au Canada et au QuSbec (1975-1985)

12 CANADA QUEBEC En 10 BTU "1*75 1980 1980 1975 1980 19o5

Charbon, coke et gax manufacture1 838.6 1186.6 1344.8 35.8 31.2 28.3 Petrole 3595.5 4471.4 5477.7 1164.6 1445.0 1787.8 Gaz natural 1573.0 2033.0 2581.0 83.6 118.9 165.8 Hydro-e'lectricite' 612.5 656.7 743.8 277.6 344.6 406.4 NuclSaire 183.0 406.0 948.0 18.7 18.7 74.8 Gaz de petrole liquefie 78.0 95.0 112.0 15.4 19.7 24.0 Consommation totale 6880.6 8848.7 11207.3 1595.2 1978.1 2487.1

Source: Energy Demand Forecast Canada (1970-1985) preparee par Home Oil Company Canada • 141

TransCanada PipeLines transportation system During 1972, a hearing was held to establish new rates for TransCanada PipeLines. It should be noted that TransCanada PipeLines did not simply ask for a rate increase, but at the beginning of 1972 submitted an application to the National Energy Board calling for the scrapping of all existing contracts with their customers & substitution of new contracts and asked for the approval of a new rate system which had no relation whatsoever to their previous rate system.

After TransCanada PipeLines made their submission to the National Energy Board, which also called for automatic tracking of increased costs and would in the future almost automatically eliminate National Energy Board control over TransCanada PipeLines, a hearing started before the Energy Board of Alberta on natural gas pricing at wellhead.

The Canadian Petroleum Association sponsored a research study by the Stanford Research Institute which went a long way to indicating markets and purported to show that wellhead prices could increase up to 20

This study of course neglects any existing contract relations between producers and TransCanada Pipelines, and obviously did not concern itself with how one gets the Federal Power Commission to agree to an arbitrary price increase at the border for gas under an existing contract.

It is understood that TransCanada PipeLines offered to substantially increase their wellhead prices as contracts come up for redetermi- nation, but the Alberta Governement has indicated that this is not acceptable.

Of serious concern to Canadian exporting industries who do not currently need an increase in gas supply is the fact that all TransCanada PipeLines rate increases after June 1, 1973 increase are created by the desire to transport increasing quantities of gas.

NEW MARKET AREAS

Advantages of natural gas distribution The availability of natural gas is an aid to industrial development.

The availability of natural gas assists in the quality control of the environment.

Mere availability of natural gas tends toward economical fuel prices, particularly in areas removed from water transportation.

Although the foregoing is a statement of fact, at the same time natural gas must be made available at a substantially lower price than propane, butane, or liquid methane in a given area for gas distribution to be practical. It must also be proven that natural gas can compete with other fuels. 142

While the foregoing is true, natural gas distribution cannot be used by much of Canadian industry at any price. Manufacturing plants which create consumer products can be insulated by import duties, and other means to some extent from international competition. However, because of our small population, other industries must export from world scale size plants to live. Energy must thus be competitive with other such plants in the world. The main problem areas are adequately covered in the recent Energy white paper published by the Department of Energy, Mines and Resources in Ottawa. One example only is used herein. An ammonia plant in Canada must compete with world scale plants on the Gulf Coast with fixed gas prices, while facing a desire by Alberta for doubled wellhead prices. Markets East of Montreal in Quebec The increased use cf natural gas offers several advantages to the economy of Quebec and the following are a few of the principal items: a) Since natural gas is the cleanest fossil fuel known, it provides an easy out in a quest for air quality. b) The mere availability of natural gas has historically led to petroleum product prices 02

The most complete survey was made by Ford, Bacon & Davis Inc. in 1954. 143

Trois-Rivieres load center, including Shawnig>n, Grand'Were: 20,000 mcf/day Victoriaville, Plessisville and Thetford Mines, from Drummondville: 20,000 mcf/day Drummondville and St. Hyacinthe: 6,000 mcf/day BScancour Industrial Park, assumed at: 16,000 Pipeline from Sable Island TransCanada Pipelines Limited has considered alternative routes for a rvHurai gas transmission line in the event that sufficient natural gas reserves are discovered on the Continental Shelf of Nova Scotia. The money for natural gas exploration off Nova Scotia is being made available partly by the two major U.S.A. natural gas transmission companies that supply New England. It is obvious that pressure will be applied at high levels to have any natural gas transmission from the Sable Island area run to Portland for connection to the systems of Tennessee Gas Transmission Co. and Algon- quin Transmission Company, with TransCanada PipeLines being supplied by dis- placement at Niagara. On the follovnnq oaqe is a conv of two nans taken from "Les Objectifs d'une Politique Qugbecoise de 1'Energie" which reflects the thinking of the Natural Resources Department of Quebec Government. 144

RESEAU (proiete) OE GAZ NATUREL AU QUEBEC, FIN 1976

FIGURE 2 145

APPENDIX "A" sse:s whare gas has physical advantages over other fuels:

A. Ferrous Metal 1. Anneali ng 9. Cutting 2. Hardeni ng If). Flame Hardening 3. Drawing n. Scarfing 4. Bending 12. Sintering 5. Bright annealing 13. Tinning 6. Carburizing 14. Atmosphere Generation 7. Carbon restoration 15. Hot Blast Air Heating 8. Normalizing for Cupola Non-Ferrous Metals 1. Galvanizing 2. Linotype & Monotype Melting 3. Crucible & Ladle Heating 4. Reclaiming Baking & Drying 1. Burn-off Ovens 2, Enamel Baking 3. Laundry Drying 4. Paper Drying 5. Feed and Crop Drying 6. Lithographing Food Processing 1. Bread Baking 9. Meat Cooking 2. Breakfast Food 10. Meat Smoking 3. Candy Cooking il. Peanut Roasting 4. Banana Ripening 12. Nut Frying 5. Cookie Baking 13. Potato Chip Cooking 6. Doughnut Frying 14. Pretzel Baking 7. Macaroni Drying 15. Hog Singeing 8. Cake Baking 16. Dehydrati ng 146

E. Ceramic Products 1. Glass Blowing 2. Porcelain Baking 3. Vitreous Enameling F. Miscellaneous

1. Asphalt Melting 2. Block Testing Engines 3. Gas Engine Operation 4. Varnish Cooking 5. Spray Drying 6. Smoke Abatement 7. Make-up air Heating 8. Grain Drying 9. Pilots for Pulverized Coal Boilers G. Petrochemicals

Natural gas and LPG used as feedstocks principally for: 1. Ammonia 2. Hydrogen 3. Methanol 4. Carbon Black 5. Many other uses 147

APPENDIX "B"

REFERENCES 1. International Petroleum Encyclopedia, 1972, by the Petroleum Publishing Company. 2. Various issues of Oilweek. 3. Various issues of the Oil and Gas Journal. 4. Various issues of Canadian Petroleum. 5. Reserves of Crude Oil, Gas, Natural Gas Liquids and Sulphur, Province of Alberta, December 31, 1971, by the Energy Resources Conservation Board. 6. BP Statistical Review of the World Oil Industry, by the British Petroleum Company Limited. 7. Various issues of A.G.A. Monthly, 8. Conservation in Alberta, 1972, by the Energy Resources Conservation Board. 9. 1971 Statistical Year Book, by the Canadian Petroleum Association. 10. Fuels Planning Conference, Sponsored by Modern Power & Engineering in co-operation with George Brown College of Applied Arts & Technology. 11. Energy in Ontario, The Outlook and Policy Implications, Volume II, by the Advisory Committee on Energy. 12. 1972 Annual Report, The National Energy Board. 13. Les Objectifs d'Une Politique Qjet :oise de l'Energie. 149

LARCH INDUSTRIAL USERS AND TH1. LiNhRPY MAI'.Kf.T

by M.D. LESTER AND J.T. MADILL

Aluminum Company of Canada, Montreal

INTRODUCTION We are sure that most of the papers at this Symposium were prepared at the last possible moment, for fear that some government, somewhere in the world9 would make an announcement or declare a policy which might do violence to the carcfully- constructed reasoning of the author's thesis. Those of us who are in the business of attempting to manage or plan any activity which depends on the availability and price of energy have been living through some hectic years, and the end is nowhere in sight.

That is not to say, of course, that we must simply be carried by the tide of events and await for some kind of stability or equilibrium to be re-established. Quite the opposite. Events are made by men, and it is all the more imperative these days that we try to bring some logic and good sense to the subject and that we try to devise counter-measures or strategies which will offset,, or at least minimize, the horrendous effects of a runaway situation.

This paper is one small attempt to focus on one sector of energy use in one country, but it would be useful to first touch on what we feel might be a scenario for the coming changes in the energy story. A SCENARIO OF ENERGY TRENDS

From the world-wide standpoint, the so-called energy crisis is really more a crisis of oil and gas. More particularly, it is a realization that, at present trends, the finite supply of oil and gas is going to run out, not centuries from now but decades from now. While the day of reckoning can, and probably will9 be postponed by some new finds, by some synthetic produc- tions by substitutions, and by more efficient utilization, the time delay thus gained will be relatively trivial.

How will society react to the gradual disappearance of a resource we have come to depend on so heavily? A time-table along the following lines suggests itself: 150

1973 to 1980 - Oil and gas prices continue to rise faster than "normal" escalation. This stimulates development of oil shale, tar sands, coal liquefaction and gasification. - At some high price, say, $1.00 to $1.50 per million BTU's, demand and supply reach equilibrium. - Electricity demand remains buoyant, as coal, hydro and nuclear generation keep power costs relatively stable. 1980 to 1990 - Oil and gas tend to be used only in applications where substitution has not yet proved feasible. )lery few new oil or gas-fired power stations are built, except for special purposes such as gas turbine peaking plants or in isolated locations that cannot support economically-sized nuclear plants. - Coal production continues to increase, but escalation of mining and transport costs start to make it less competitive than non-fossil electricity for power generation. - Many of the remaining feasible hydro sites are developed, including those in Quebec and British Columbia. - Nuclear power proliferates, and the breeder reactor undergoes intensive development work and demonstration testing. 1990 to 2000 - Electricity accounts for more than half of the total world-wide energy consumption. - Most electricity is now being generated by old conventional nuclear reactors and new breeder reactors. Coal- fired power is still being produced where the logistics are favourable. The remaining massive hydro schemes of West Africa, South America, and the U.S.S.R. are developed. - Petroleum, natural gas and synthetic hydrocarbons now considered primarily as either chemical feedstock or special-purpose materials, rather than bulk fuels. After 2000 - Electricity becomes increasingly predominant as man's principal energy source, with transportation based on electric motors and batteries rather than diesel and gasoline engi nes. - Hydrocarbons used principally for feedstock, lubrication and aircraft fuel. - Concern mounts over the radiation and thermal pollution effects from the enormous number of nuclear power stations. Reports indicate that the finite supply of uranium and thorium will run out not in centuries but in decades. 151

- The fusion reactor is perfected and plants located in the oceans provide power and hydrogen for eons to come,

THE PENETRATION OF ELECTRICITY

Whether or not the above timing is correct, the inescapable facts are that (a) we are moving toward an all- electric society; (b) the growing demand for electricity will be met by non-fossil fuel sources; and (c) fossil fuels will increase in price, reflecting their value as chemicals and special-purpose, non-replaceable materials.

The actual price levels involved in these trends are difficult to forecast and, in any case, will always be subicct to wide variations due to location and national policies. But let us say that, in 1985, oil and gas laid down at industrial load centers around the world will be worth about $1.50 per million BTU's. (This is equivalent to about $10 per barrel of oil or $1.50 per Mcf of gas.) Electricity might, by then, have stabilized at around 10 mills per kwh generated by nuclear additions. At these comparative prices, oil and gas could compete with electricity only in direct heating applications and, even here, such a utilization of hydrocarbons might be discouraged, in order to conserve and stretch out the fuel resource inventory. Environmental considerations will also serve to discourage burning fuels and to encourage non-combusticu production of electricity.

In Canada, the situation is rather unique and rather more favourable than elsewhere. first, we are blessed with extensive hydroelectric resources which today account for three- quarters of our electricity and one-quarter of our total energy demand. This, together with new hydro developments nov.< being planned^ form a substantial base of low-cost power - one which becomes eyen more attractive with age as facilities are written down well within their useful life. Second, our uranium deposits guarantee that we will be able to move easily into the forthcoming nuclear era, particularly in view of the recent success of our CANDU design which does not require expensive uranium enrichment. Third, we have enough coal, oil and gas resources to remain self-sufficient for a considerable period. This, in turn, leads to a number of options as to how we handle our fuels. Do we husband them carefully to last as long as possible? Do we exploit the present and future world market situation by selling as much as possible as fast as possible? Or do we steer a middle course by a two-tier system which brings some export profits to Canada and, at the same time, insulates us to some extent against high world prices? L)o we encourage the establishment of fuel-based industry at or near our oil9 gas and coal deposits? And how do we take advantage of our inherently lower electricity costs? Do we export power 152

as such or do we prefer to "package" it within our borders and sell it in the form of refined metals or enriched uranium? Whatever the final resolution of these auestions, we believe that Canada will undergo the same evolution as the rest of the world, i.e., higher fuel prices and a shift to non-fossil electricity where possible. The principal difference, and it is an important one, will be a generally lower price structure here than in most other nations.

Let's now turn to the subject at hand:- How will Canadian industry fare in this new scheme o? things?

THE IMPORTANCE OF ENERGY TO CANADIAN INDUSTRY

? To say that energy costs do not exceed 10 o of the cost of doing business for most industries in Canada, which happens to be true, conceals the wide range of impacts that are actually involved. To the banking industry or to the insurance business, higher heating and lighting costs are nothing more than a minor nuisance. But for ethylene or ammonia producers, where energy sources account for three- quarters of production cost, the problem is quite different. If any general observations can be made on the importance of energy to Canadian industry,, and in this we concur with the findings of the recent Federal publication, "An Energy Policv for Canada", they are that:-

1. Higher energy costs could place some industries in a very difficult position, and special protection may be needed for an interim period. 2, Higher energy costs would not be significant for most industries, except where their products may be competing with alternative materials whose costs are not increasing at the same rate as energy costs.

Let us take a closer look at four major Canadian industries in which energy costs play a key role. Pulp and Paper accounts for almost one fourth of industrial energy consumption in Canada and energy, in turn, represents about 12% of the cost of production. This consists of botli the direct use of fuel and electricity and the indirect use by way of the energy required to produce the chlorine and caustic involved in papermaking. There could be some additional switching to electricity for steam-raising. Our competitive position will not be affected by a world-wide increase in energy costs so long as Canada maintains its present differential advantage, particularly in electricity. The industry's domestic and export market is more likely to be influenced by such factors as increased recycling of paper and development of synthetic paper. 153

Chemicals are notably affected by the cost of the fossil fuel resources which are the raw materials of this industry. They represent over 20% of production cost, on the average, and considerably more in some cases. Where natural gas is the feedstock, our competitive position vis-a-vis the United State, is quite sensitive to the relative prices of this commodity in, say, Ontario and the Gulf Coast. Rising prices of Canadian gas over the near term may be offset by similar tendencies in the U.S.A., but there could be certain timing problems involved because of existing long-term contracts. Oil-based feedstock costs will not increase disproportionately in Canada, and electricity prices, as noted previously, should retain a competitive advantage. Perhaps the principal problem in this industry, wherever located, will be the loss of markets to alternative materials if cost increases are passed through.

Iron and Steel output includes about a 15$ expenditure on energv out of each do'llar of production. Heating fuels and metallurgical coal account for the bulk of this item, although some increase in the use of electric furnaces is expected. The principal feature here is that, while Canada is more than self- sufficient in metallurgical coal, its steel mills import their requirements from the U.S.A. (mainly from mines owned by the Canadian mills). At the same time, Western Canadian coal is exported to Japan, and at a growing rate. There is no reason to believe that the logistics of this situation will not remain favourable.

Non-ferrous metals are closely identified with energy. The Canadian aluminum industry alone generates and consumes about 10% of all the electricity in the nation, plus a considerable amount of fossil fuel. The availability of abundant, low-cost power was and is instrumental in Canada's development as a leading world producer of the major non-ferrous metals. In the case of aluminum this factor was sufficient to offst. the absence of the raw material and to compensate for the logistical difficulties involved. If and when electricity costs equalize around the world, at whatever level, Canada would lose some of its competitive edge. However, a large portion of the electricity supply in Canada to this industry is based on low-cost facilities, relatively free from future inflation, and a considerable amount of additional generation could be made available befoTe this advantage would diminish. For this reason, we would expect to see continued growth of this sector in Canadat at a time when expansion elsewhere is becoming difficult.

ADAPTATION BY INDUSTRY Industry in the developed nations of the vorld accounts for about one quarter of man's energy requirements, and this ratio is expected to persist. To what extent can or will the industrial sector participate in the over-all shift to primary 154

electricity? To answer this we need to look at the various applications to which industrial energy is put.

1. To drive motors, pumps, fans, vehicles, etc. Much of this is already electric-powered and the trend will grow,

2. To raise steam. This is now accomplished by means of all the fossil fuels and primary electricity. We expect coal to play an increasing role here and, in the longer term, a more pronounced move to electricity or perhaps direct use of nuclear heat. 3. To dry or melt materials and to heat spaces. This is a relatively efficient utilization of fossil fuels and will be supplanted by electricity or nuclear heat only over the longer term or in special economic circumstances. 4. To cool spaces. Already largely electric, but more emphasis will be placed on efficiency and insulation.

5. To provide light. Already electric. 6. Direct electrolytic use. Already electric and, by definition, remains so. 7. Direct use of fuels as feedstock. By definition, no substitution is possible. The emphasis here will be on the use of relatively abundant coal as the basic raw material and on recycling.

The conclusion to be drawn is that the trend to greater electrification by the industrial sector will not be as pronounced as in the transport and residential sectors. Recent forecasts for Canada indicate that, while industry uses more than half of the nation's electricity today, the proportion will drop to about one third in 25 years.

SUMMARY

1. The finite supply of petroleum and natural gas and the fact that no substitutes are yet available for certain applications will lead to higher world prices for these resources.

2. The higher prices will stimulate additional supplies by means of oil sands, oil shales, coal gasification and liquefaction, and frontier drilling.

3. The new equilibrium price will be sufficiently high to cause a world-wide shift to electricity, mostly based on nuclear generation, at costs not markedly different from today's power costs. This will be particularly true in the transport and residential sectors, since the industrial sector is either already highly electrified or uses energy resources as feedstock, 155

4. The entire Canadian economy, including the industry sector, will continue tj benefit from a relatively lower energy cost structure, based on self-sufficiency in fossil fuels and uranium and on favourable hydroelectric resources.

5« For most Canadian industries, energy is a relatively small component of production costs. There are a few important exceptions but, in most cases, any energy cost increases will likely be matched by similar or greater increases to foreign competitors. Some industries could be in difficulty for an interim period and may require special action to ensure their survival. 157

HYDROCARBONS FOR TTROCHE'UCALS

O.C.

Gulf Oil Canada Research Centre (now with Gulf Oil Corporation, Pittsburgh, Pa., U.S.A.

M, le President, je veux exprimer mes remerciements a la Societe fovale tiu Canada, qui a oosse"de la vision de orevoir , il v a quelques mois, la maturation de ces nrobiemes d'energie et d'orqaniser ce colloque a une con.joncture si convenable. C'est un grand Dlaisir de presenter queique remarques a votre invitation, et ^'espere qu'elles contribueront a quelque chose en exDOsant les details de la situation. When we look at the petrochemical sector as distinct from the total energy picture, some important differences appear. For one thinn, vou probably know already that chemicals from petroleum have been distinguished in recent years by relatively rapid growth. You mav not know that they are also distinguished, especially in the last six or seven years, by an ability to lose remarkably large sums of money for many manufacturers. I hope vou will not be bored if I spend a few minutes on these and some other distinctive •Features of the petrochemical industry. 1. Rapid Growth Volumes of overall petrochemical use in North America seem to be growing, in the long-term trend, at a rate around B% per year. This is considerably faster than total energv demand, for which a growth factor commonly assumed is a little over 4%. However, before vou get too alarmed, remember that chemicals are products whose usage, though large, is measured in pounds, not barrels. Right now, in Canada, it is a good estimate that sliqhtlv over ?.5"' of liquid hydrocarbons being produced, and somethinq under ?,"'• of natural qas, are being used as petrochemical feedstocks. Even if this chemical stream were to grow until 1985 at 8" per year, with hydrocarbon production qrowinq at half that rate, the percentage of total hydrocarbons qoinq into petrochemicals in 1985 would only be a little over 4°'. It could constitute a much larger percentage, of course, of certain selected hydrocarbon cuts. At the moment, for example, a shortage of naphtha seems to be developing, due to demands for gasoline and for synthetic natural gas. There is one possible development which could raise the oercentaqe of hydrocarbons going to chemicals. This is, large-scale conversion of natural gas to methanol in order to get it out of remote production areas. I will come back to this later. 158

2• Large and Expensive Individual Plants The trend to large-scale plants was verv marked in the last 10 years. Commercial ethvlene plants in 1960, for example, were as small as 100 million pounds per vear. Now a new plant would be ten times that size. 'In ammonia plant of 120 tons per day used to be considered large. Now the economic size is 1,000 to 1,500 tons. I hardlv need to dwell on the difficulties which these changes of scale impose on a country like Canada, where a small population is spread over long distances, and where there exist various barriers to large-scale exports. 3. Importance of International Movements In most cases, basic petrochemical plants are in competition with similar plants around the world, unless their homeland adopts deliberately a policy of self-containment, a thing which Canada has not done. In the absence of man-made regulation, the main natural restrictions to movement are transportation costs plus the fact that certain products are difficult to shin — for example hydrogen, or acetylene, or ethvlene, 4. Price Competition Petrochemicals in the last ten years have been terrifically competitive in price. While the costs of almost everythina else have . .en aoing uo, selling prices of basic Petrochemicals not onlv fell, thev fell dramatically. For example, between the late 1%0's and early 1970's, in the United States: Ethylene fell from R(t ner pound to under 3t Vinyl chloride fell from around °it to &.?5t Phenol fell from 17v financial institutions. Be that as it mav, this coalescence took place in 1S9

France, Italy, the Netherlands, Great Britain and elsewhere at about the same time. Let me just show the situation of France as an examnle.

Significant French Petrochemical Manufacturers 1960 - six 1973 - two

Kuhlmann Pechinev-Hqine-Kuhlmann Pechinev Rh6ne-Pou1enc Progil

Rhone-Poulenc St. Gobain Ugi ne Now have a look at what has happened in Canada, which has a nonuiation about two-fifths that of France. Significant Canadian Petrochemical Manufacturers

1960 - twelve 1Q73 - fifteen Chemceli Badische C-I-L Chemceil Comi nco C-I-L Dow Cominco

Du Pont Oow Ethyl Ou Pont Goodrich Ethvl Gulf-Shawinigan Goodrich Monsanto Gulf-Shawiniqan Polysar Hercules Shell Imperial Union Carbide M&nsanto Polvsar Shell ^ Union Carhide

- II- - 160

!n addition to all twelve who were active in I960, three mora organizations have entered the fie id.

6. Sensitivity to Feedstock Costs

Because of the highly competitive and international structure of the industry, not only the Drofitability but the very viability of Canadian netrochemical operations is verv sensitive to raw material and fuel costs. This is narticularly so since many oetrochemical processes have hiqh fuel and newer usage. A refinery tvDicallv burns about H% of the hydrocarbons charged to run its ODerations. In an olefin plant the figure could he 30%. Whatever the absolute levels of raw material and fuel costs are, thev have to be competitive with those elsewhere.

7. "1objmy_ Unlike the energy structure as a whole, the oetrochemical industry is mobile. If conditions are not favourable in one place, new plants will be loc^teo in another orovince» another country, maybe even another continent. It is interesting to see this concern in a recent paper by Mr. William Trammel!. f^r. Trammell is an astute observer in a large international engineering company. In the April 30, 1973 issue of Chemical Engineering he savs, sneaking of mobility from the United States' viewDoint: "In the longer term, chemical-industrial economics and logistics will force serious consideration of locating new facilities overseas (including Canada) near low-cost gas resources." Although he is speaking specifically here of gas, vou may be sure that the same could be said of hydrocarbon liguids.

Now, I would like to go on to say a few words about three individual 1.1 asses, of basic petrochemicals. 1. Synthesis Gas Products These are all made through a synthesis gas containing various oro- oortions of carbon monoxide and hydrogen.

Hvdrogen: CO + nH? + H.,0 + (n+l)H, \\ ? Ammonia- 1.5H<, +

CO + 2H2 CH3OH

Oxo Process: R-CH=CH? + (plus aldehydes, isomers)

Svntftesis «?as H usually ma&' today bv steam reforming of natural o other Itqht hvdrocarbons, but it Mr? also be made fro:* i ii. So f; _ raw materials cost is concerned, the cheapest place to make \t will he <,.>e point 161 of feedstock production or importation, as the case nay be. In tM<; reqard, the large-scale conversion of remote Arctic gas to methanol, near the wells, mav become a serious alternate to moving out the qas itself. Theoretical lv 16 pounds of methane, the chief constituent of natural qas, can be converted to 32 pounds of methane! which still retains 82% of the heatinq value of the original methane. In practice the fiqure would be lower than R2W because of vield losses and fuel needs in the conversion olant. Methanol is a stable non-corrosive liquid, boiling well above ambient temoeratures and freezinq at -144°F. Furthermore, it can be burned directly as fuel. There are even Dromising developments toward a fuel cell which could convert it directlv to electricity. Its use as a netrochenrical is limited, mainly for oroduction of formaldehvde. So even though technically we call it a chemical, the large-scale conversion of natural gas to methanol would be reallv a conversion of one fuel to another.

2. 0Tefins These are mainly ethylene, oropvlene, butanes and butadiene verv important basic materials all. As feedstocks for these methane, the main constituent of natural gas, cannot be used. But the heavier hydrocarbons in natural gas -- ethane, propane, butane being the main ones -- can. You can also crack naphtha, or even heavier materials un into the furnace oil range. In Japan there is even a prototype unit cracking crude oil directly, without any preliminary refining. If natural qas liquids are used, the cheapest place to produce olefins is undoubtedly near where the natural qas liquids are separated. That means the gathering areas for natural gas nipelines. Dropane and butane are largelv removed from natural gas before it enters the pipeline. Ethane does not have to be taken out of the nineline gas but, of course its alternative value, for fuel, will be higher at the end of the line than at the beginning. If a liquid like naphtha or distillate is the olefin feedstock, the place where it will be available most cheaniv will be the refinery where it is produced. Locating an olefin nlant near a refinery also permits optimization of Diping, tankage, shipping facilities, nossiblv utilities and other expensive off-site items. There is also the noint that when naDhtha or middle distillate is cracked, large quantities of hydrocarbon fuels are produced as ccoroducts. Canadian natural gas, as marieted today, contains -erv substantial quantities of ethane. Technology i> -'r^'able for removinn ,:nvthinq un to W% of the ethane content, although i *.s rise as you nass 50% recovery. At the present moment, Canada.. natu,. ,;s production is runninq rnuqhlv at the rate of 3 billion cubic feet ner dav, of which 5.9% bv volume has been estimated as an average ethane content. Recovery of half of that ">ould give 2.5 billion pounds ner year of petrochemical feedstock -- anoroximatplv enouqh to supply two world size ethylene plants. Actuallv, the ethane being recovered in Canada today is about 90 million pounds, less than ?.% of the total in natural gas being Droduced. As .nany of you know, there are oroDosals now in the project stage to utilize this valuable feedstock component. 3. Aromatic Chemicals Benzene, toluene, xylenes and cumene are the main orimarv products and all are normally Droduced at a refinery sice, since they are extracted or derived from refinery streams by relative!v simnle nrocesses. If th£ 162

refinery is integrated with an olefin plant, aromatics from the refinerv and from the olefin plant can be recovered together. Summarizing, with some thoughts about the future of the petrochemical industry in Canada, reminds one a bit of the disDutes over nonula- tion Droblems. There seem to be two alarming and ODoosite viewpoints -- one that there may be so many people on the earth that we aDnroach standing room only5 and the other that there mav be no neoole at all. In the Canadian petrochemical situation, we might either eat up all the available hydrocarbons as feedstocks, or eat up none. To be truthful, I do not think reallv that the first situation is likely. Over the next twentv vears, nearly all ethane and a large quantity of natural gas liquids may be needed for oetrochemicals, and there will almost certainly be problems in supDlving sufficient naphtha. But overall, petrochemical demands are not likely to intrude seriously into the total volume of hydrocarbon supplies.

A much more real danger is that the Canadian petrochemical industry might wither away to a shadow, as the result of competitive pressures which is is not structured to meet. The extreme case would be one recommended quite seriously a few years ago at a meeting of chemists in Toronto. The speaker was a consuHant for a large financial institution to the south of us. His view was that a simple solution existed to Canada's petrochemical problems; namely, shut down the Dlants in Canada and imoort whatever was needed. I am haDpy to see that there are recent signs of progress toward more constructive solutions. In one region of petrochemical manufacture in central Canada, a series of suoolv agreements has led to at least some rationalization of manufacturing activities. In another region a concerted effort is being made to reach economic scale in several basic oetrochemicals. Personally, and here I speak only for myself, I wonder whether these are only beginnings. Speaking as a technical man and not as a legal expert, I wonder whether the real answer, if we are to attain a viable status in petrochemicals, includes central ooeration in each area of at least services and utilities. Mavbe each economic area should have a single operating company, probably with multiole ownershiD. It will be interesting, and it will be a real test of Canadian ingenuity, to see how the present efforts develoo. 163

ENERGY AND CANADA'S TRANSPORTATION INDUSTRY by

W.S. WILSON Canadian Pacific Ltd., Montreal The transportation industry is confronted with energy supply problems as both a very large consumer and a major factor in the chain necessary to produce and market fuels. Changes in the price and availability of energy have already altered our industry and I am sure there is much more to come.

Looking first at transportation's role as a consumer of energy, the most striking fact is that 99%, or more, of the fuel used is products of oil. This almost total dependence upon a fuel, which is faced with supply disruptions, rapidly rising prices, political manoeuvering and, in the long term, eventual exhaustion of reserves, is indeed troubling. In total, the transportation sector consumes slightly more than 1/4 of all our energy. Over half of this energy is gasoline for autos. Trucks and buses account for about 20% of the consumption, followed by the relatively small consumptions of the air, rail, pipeline and marine modes.

Large differences exist in the efficiency with which the various transportation modes use energy. Fiqure 1 shows how Prof. Richard Rice ol Carnegie-Mellon University compares the relative efficiency of pipelines, marine transportation, train, trucks, and aircraft. These are generalizations and it can be appre- ciated that there are large differences within each mode. For example a 40-car freight train requires many times more fuel per ton mile than a 100 car freight train. Overriding this, however, it can be seen that pipelines, marine, and rail transportation are much more efficient than trucks and aircraft in the consumption of fuel.

In the past, the commercial transportation industry has accepted and lived with these large differences in efficiency. Fuel costs were stable and in many cases not an important or controlling factor in the cost of service provided. I don't expect this to continue and already rising fuel costs are a serious concern within the trucking and airline industries in particular. Figure 2 shows how freight transportation requirements are now provided. Surprisingly, the majority of intercity movements are now supplied by the most energy efficient modes: pipelines, rail, and marine. Ir, terms of ton miles, less than 10% of freight is carried by trucks ajid aircraft, 164

RELATIVE FUEL EFFICIENCY OF TRANSPORTATION

LARGE PIPELINE L INLAND BARGE TOM L 100.000-TOM SUPERTANKER L 1GQ-CAR FREIGHT TRAIN L QQ-CAR FBEIGH7 TRAIN 1 I TURBOPROP AIR FREIGHTER Q LARGE CARGO JET (747) • QO-TOH TRUCK

I- I 100 200 300 100 500 600 700 800 900 1000

TON MILES OF CARGO PER GALLON

PHOF. RICHARD RICE. CARNEGIE-HE LLON UNIVERSITY Fig. 1

TOTAL INTERCITY DOMESTIC FREIGHT

(250 BILLION TON MILES - 1967)

RAIL 37*

OIL PIPELINES 182

GAS PIPELINES 72

TRUCK AND OTHER 91 Fig.2 165

our least fuel efficient modes. Despite this small percentage of the total freight business carried by these modes, they are very intensive users of fuel.

Faced with rising fuel costs some shift from the less efficient to the efficient energy using modes seems certain to occur. Rail's competitive advantage with the intercity trucking industry for example will grow and certain shippers will be attracted by price.

As noted earlier there are large differences in energy efficiency within each mode. Large trucks„ trains, and planes are more fuel-efficient than small ones and fuel costs will be an important factor in the further introduction of these larger units. I would not look for dramatic changes in our transportation systems but rather the evolution of a more efficient mix of transportation facilities to serve Canada's industry.

The extreme dependence on oil is promoting study of other energy sources for transportation. With the exception of the nuclear ship, most of this work involves the application of electric power to transport. A completely practical electric car, unhappily, still eludes its developers and does not appear to figure in resolving our current fuel shortages• Electrically driven trains and pipeline pumping stations are, in contrast, a very practical matter and are now commonplace in some parts of the world.

The electrically driven pipeline pumping station has been widely adopted in Canada for over 15 years. Electri- cally driven gas line compressor stations have been less common, but have been adopted in parts of Eastern Canada. The electric drive, in addition to favourable energy costs, also offers the pipelines significant savings in operating and maintenance manpower and permits a degree of automatic operation not possible with oil or gas fired units.

Canadian Pacific and other railways in North America have been giving increasingly serious consideration to the electrification of high traffic density rail lines. Since 1971, diesel oil prices to the railways of Canada have risen nearly 40%. This rise is a strong motivation for electrification studies but not the only reason- Electric traction has been common for a long time in Japan and Europe and offers higher speeds, better performance on grades, and simplified (and therefore more economic) maintenance compared to the diesel. Recent innovations in electric locomotive design and lower cost means of bringing the power to the tracks add to the attractiveness of the idea. 166

DOMESTIC ENERGY FREIGHT

(8t BILLION TON MILES - 1967)

OIL PIPELINES 55X

GAS PIPELINES 261

TRUCK WATER « 21 Fig-3

Fig. 4 167

There appears to be a marginal improvement in the overall energy oliiciency of the electric locomotive over that of the diesel. In other words, when a gallon of fuel burnt in a ciiea&l is compared to that same gallon of fuel burnt .•'n =i never plant and then transmitted to an oloctrie- locomotive, the electric system delivers slightly more effective horsepower to pull the train. While this is encouraging, the really important aspect is that the electrical energy could be generated from the same oil or, alternatively, any other fossil fuel, nuclear, or hydro resource. Our conviction is that while all these energy costs will likely increase, the oil to which we are now captive for rail operations will likely rise more rapidly than the whole mix of energy sources. Electric power production, fortunately, has the flexibility to shift to the optimum sources of energy as our electrical systems expand. It also appears much more practical to deal with potential pollution problems at a limited number cf large generating stations rather than to control emissions on each individual locomotive. In Ohio the Muskinguiti Railroad is now operating and in the U.S. southwest the Black Mesa and Lake Powell Railroad is under construction. These are the first modern electrified railroads in North America and don't be surprised if the idea spreads from these beginnings.

While the flexibility to electrify does exist in the railway and pipeline industry, unfortunately, there appears to be no such scope for reducing the oil consumption of autos and trucks. While the social objectives of the new emission rules can't really be questioned they are reducing the gasoline efficiency of the auto by a further 30% to 40%. Increased costs and shortages will almost certainly lead to lower horsepower cars and more measures to reduce speed limits as have already been instituted in parts of the U.S. as a fuel conservation measure. I am sure Dr. Soberman will talk about urban traffic congestion and, hopefully, will give us some alternative for that large share of auto usage which occurs within our metropolitan an-as.

Turning now to transportation's role as a mover of energy, Canada is richly endowed with energy resources and the transportation of these resources to market is a major industry. Figure 3 indicates the relative importance of the various modes in moving energy to market. Unfortunately, the story is incomplete as it ignores the very important transfers of energy by wire - frankly because statistics on this traffic are hard to find and almost impossible to present on a comparable basis. The domination of oil and gas pipelines in these other movements is however obvious. 168

Tne really remarkable thing is that 25 years ago the pipeline mours scarcely figured at all in national transportation and today they not only dominate in the energy traffic but represent 25% of all intercity freight ton miles generated.

Me ;' interesting and challenging ideas are being considered for the further development of our energy transportation f aa\ "! i tJer .

The generation of electric power at coal mines and long distance power transmission using either A.C. or D.C. techniques to replace the physical movement of coal to consumption centered generation plants.

Coal gasification and shipment oy pipej. r^. Deliveries of foreign oil and gas by large crude carriers (V.L.C.C.'s) and liquified natural gas ships and the companion deep water porL and domestic delivery facilities

Slurry pipelines delivering coal in either water or oil mediums. Further refinements in the unit train concept for large scale coal movements. At this time the issue which has attracted the most attention is the development of Arctic oil and gas resources aad a further large expansion of our pipeli^ ^- stem. Much st'-iy has already been di" ^ct^1 ô ^luat^.g v • vious Arctic pipeline routes. As Picture '• s ows, t; e Maci' r/.ii Valley Pipeline Group has st.di'J ?.. >il Une i the Western Arctic, 'vhile CriLc'.an Arctic âs Sûriy Lti1 and ..he Polar Gas Group have stu 'ei gas lims ser-'ii-} fcist-rn a Eastern Arctic reserves.

Other rnoc.es of Irving frosc /c.-ources are also receiving serious consi^ei jtj'-n. \ ^mi-cry • t" Transport sponsored study is now reviewiu* th^ tn<5"ibnit>s of a railway providing access to +hfe W^^^err rcti;. others have considered ships and air . c, net .-.!". i •"„-*corsid..u'-. :• l^gf, c so been given to conve thesr fu' Is to lerf j_'j\ty in the Arctic and transpor'.my to marjv ^t "< ^.a -jise. ' t will no doubt learn a great deal from th ir >:c. npcia--. i,e work but, in my view, the pipelines seem !o oil'r ' :a TOS: economic means of solving the specific probleir of br nging this oil and gas to market.

While gas .>nd oil prices are rising rapidly, it is well to remeir.b' - at even at $6/barrel for oil and $1/M.C.F, for gas we are st"11 sealing with a low value commodity 169

worth no more than $50/ton. A highly efficient mode of transport must then be offered if the oil or gas is to be moved at all. Pipelines have historically offered this kind of efficiency and thus account for the largest share of all such movements on land.

A further point is that the most apparent energy resource in the Canadian Arctic is natural gas. While it is possible to liquify this gas and move it by ship, plane, or train, this concept is only now receiving limited commercial acceptance. L.N.G. is created at the exceedingly low temperature of minus 258 F. A liquification plant is then a costly and sophisticated piece of equipment to achieve these low temperatures while the vessels to store and ship the L.N.G. are gigantic and costly "thermos" bottles. Compared to the simplicity of pumping gas through a pipe, the complications of liquification and maintaining cargoes at their low temperatures are a serious hinderance to considering any other transportation mode for gas.

Much the largest amount of research money has now been spent on studying the pipeline alternatives. In total this research work will soon have cost more than $50 million. The innovations to deal with Arctic problems, advanced route selection, design and other results of these expenditures mean a pipeline could be installed sooner than any other system. For example, the concept of pumping refrigerated gas to preserve the integrity of permafrost soils has now been thoroughly proven and demonstrated. Metallurgical advances have made it possible to plan for higher pressure and therefore much more efficient pipe systems. In contrast, an immense development budget would be required before a prototype aircraft gas freighter could get off the ground. A ship's hull, capable of reaching most of these areas year round, is neither in existence nor under construction anywhere in the world and, further, would take millions of dollars and some time to build and test.

The selection of transportation systems for the Arctic will be a decision of lasting importance for the region and Canada. It is proper that all aspects receive a thorough review prior to making that decision. We should, however, not fall in love with studies for the sake of avoiding decisions on the question, or ignore the very fundamental and, in my view, governing advantages of the pipeline mode in the specific applications involved. 171

ENERGY MARKETS AND URBAN DEVELOPMENT

by J. PILL Metropolitan Toronto Transportation Plan Review, Toronto

INTRODUCTION This paper attempts to assess the impact that the impending changes in our energy market will have on urban development in Canada, especially in a large city such as Toronto. There has been some speculation that the "energy crisis" will drastically change our way of life. It will be argued here that the urban characteristics that are currently most visible in shaping our cities -- land prices, transportation congestion, job opportunities, socioeconomic factors -- will continue to be important to the year 2000, and the energy situation per se probably will not have an overriding influence, although it will increase in importance. Energy will cost more, and it will come in different forms, but most people will still be able to obtain enough energy to live basically as we do now. We shall first present the energy projections to the year 2000 which will constitute our basic assumptions. Next, we shall briefly introduce the basic elements of urban land-use/transportation planning, and discuss some of the planning issues. The technological implications of the year 2000 energy projections on land-use and on transportation will then be examined, with some inferences concerning the impacts of the technological changes on urban form. Finally, a few tentative conclusions will be drawn regarding the overall relationship of the energy market to future urban issues. CANADIAN ENERGY TRENDS 1 2 We shall accept the recent federal and Ontario middle-of-the- road projections as a baseline, and present some of their conclusions as our starting assumptions. These projections involve reasonable premises but are subject to large variation depending on population growth, economic growth, and world politics. For instance, the federal estimates for population in the year 2000 range from 29 to 38 million. Given these qualifications, the following projections are presented: (i) Canada's energy requirements in 2000 will be four times those of 1970. (ii) Canada will be able to meet all of her energy needs to 2000 from indigenous sources. (iii) Increasing prices for energy commodities will tend to moderate demand growth rates in the long run, without government inter- vention, (iv) In 1990, crude oil prices will be more than double today's prices. 172

(v) The cost of natural gas will double or triple by 1990. (vi) Cost of electricity will continue to increase to 1980, but will tend to level off as technological advances are implemented, 2 Some specific projections are available for Ontario. Energy consumed for residential and commercial heating is expected to decline from about 20 percent of total provincial energy use to around 1J percent. The transportation sector accounted for about 17 percent of total energy consumption in Ontario in 1970, and this will rise slightly to 19 percent by 1990. Fuel consumption by motor vehicles accounted for four-fiftns of the 1970 transportation energy use; this could well decline by 2000. Industrial consumption of energy will increase slightly as a percentage of the total between 1970 and 1990, from 30 to 34 percent. Ontario Energy 2 Demand Transportation Residential 8. Industrial Total Commercial 1015 ETU 1970 16,8 26.6 29.8 2.35 1990 19.3 21.1 34.2 5.7 THE URBAN SYSTEM In urban planning, three interacting physical elements determine the urban pattern: land-use, transportation, and sewer and water services. For purposes of this discussion, we shall assume that in Ontario the provision of sewer and water services will be independent of energy cost to the year 2000. Land-use can be divided into three main categories: industrial, commercial and residential. There is a well-developed state of the art in land-use planning3, but a detailed discussion is beyond the scope of this paper. Within the context of overall development trends based on the economic base, land availability, demographic factors, and the level of transportation service, it is quite possible that energy cost could influence the design and location of buildings. This will be considered. The effects of the energy market on urban transportation might cause some concern because of the visibility of the recent American problems with gasoline supply. Gasoline purchases currently account for about one fourth of the cost of operating the average Canadian auto1, and with a doubling or tripling of gasoline prices within the next two decades, the concern might'be justified. In public transit, energy cost is a much lower percentage of total cost, constituting for example about 7 percent of the Toronto Transit Commission's expenditures in 1972.4 A large number of factors affect land-use and transportation in the city, and energy cost is currently not one of the major ones. We shall examine the direct effects of an energy cost increase, and try to assess the importance of these effects relative to other influences. 173

LAND-USE AND ENERGY COST There are two ways in which energy cost could have a direct effect on urban land-use. First, if transmission and transport of energy are expensive, decisions on location could be affected. Second, as heating costs become more significant, they could influence the design and form of buildings. There is little reason to believe that the cost of transporting energy will increase as quickly as cost of the energy itself. Wellhead prices for gas and oil will rise more rapidly than construction costs for pipelines and tankers. Electrical transmission losses will be a more or less constant percentage of total generated power, so as the price of electricity rises so will the cost of transmission, at almost the same rate. Therefore, electrical industries might tend to locate closer to the power source, e.g. a nuclear plant, other factors being equal. This might have some effect on urban industrial expansion by the year 2000. The availability of labour, markets for the product, transportation, raw materials, and land will continue to be important. The specific location of a plant within an urban area will be determined more by land cost and access than by energy transmission costs. Overall, industrial location decisions will be made as they are now, with energy transport costs becoming slightly more important. Increased heating cosls could influence urban form in the long run. Multiple-unit buildings are cheeper to heat than single family houses because of their lower surface-area/volume ratios; this will tend to drive up the ownership cost of the latter, reinforcing trends caused by high land costs. The government might at some time impose minimum insulation standards; "electrical standards" could reduce energy consumption per building by 3C percent compared to current standards.1 However, this woi/d require careful study to be certain that the discounted value of enenj•/ saved is greater than increased construction costs. In Ontario, use ot natural gas and electricity will increase substantially by 1990-, and depending on price structure, will be used more for heating than they are presently. By_2000, the cost of electricity should be cheaper than either gas or oil^>2>5, so in the long run a changeover to electric heating can be anticipated. The uS3 of "district heating" might prolong the use of oil and gas. Aside fror-; a greater concern for heating costs and some reinforcement of the trend to multiple-unit dwellings, it seems that these technical changes will not cause any major reorientation of urban trends. ENERGY AND URBAN TRANSPORTATION The gasoline shortages in the United States during the summer of 1973 portend a basic change in our use of energy for urban transportation. The cost of a gallon of gasoline will at least double in Canada by the year 19901, and automobiles will be quite different from what they are now. As these technological and economic changes might seem to have a potential for changing our life-styles drastically, we shall examine them in detail. 174

Automobi1es The automobile has already undergone significant changes in North America during the past five years to meet government standards for exhaust emissions and safety. The net result for the consumer has been a reduction in performance and efficiency and an increase in cost. The 1976 emission standards for the United States will entail losses of about 20 percent in both power and gasoline mileage relative to an uncontrolled engine , Canada's standards will be somewhat less stringent, but not much.

The impending increases in gasoline prices will result in further changes in automobile design in the United States. There is a conflict in design objectives: to reduce energy consumption one must reduce weight and increase efficiency, while the current safety and emission standards increase weight and reduce efficiency. Trade-offs will be necessary. The most straightforward means of increasing gasoline mileage is to reduce the weight of the car: a 5,000 pound auto consumes twice as much fuel as a 2,000 pound one, and its mileage is reduced by another 25 percent by power steering, power brakes and air conditioning^. There are already signs of change: in Los Angeles, the vanguard of the American automotive culture, Pintos now outsell large Fords, no doubt largely due to well-publicized problems with gasoline supply?. Even Cadillac has a compact car in the works. A number of proposals have been made in the U.S. Congress to apply purchase taxes on automobiles based on gasoline mileage^. The technical and political factors thus point to an inevitable trend to smaller cars.

The Canadian automobile and petroleum industries are controlled by American firms, so it is unlikely that Canadian automobiles can differ significantly from American ones for very long. Thus there will be a parallel switch to smaller cars in Canada. There will also be a series of technical changes in the motive power, in which both energy and environmental criteria will play a part. Automobile engines will go through three (probably overlapping) stages by the year 2000: (i) refinements on the conventional internal combustion engine; (ii) new engine types powered by hydrocarbons; (iii) electric power. It is difficult to predict when the changes in power source will occur:

What is in the future [for the U.sT^ ? Through 1985 motor vehicles with internal combustion motors using petroleum fuel and travelling on widened and extended highways To predict beyond 193b would be to enter the tla-eshold of speculation^1. We shall now describe some of the technological and economic factors, and then enter the threshold of speculation.

The conventional internal combustion engine is operating close to its limit in emission reduction; to meet the 1976 United States standards it will probably require catalytic exhaust converters. It appears likely that these standards will be eased somewhat with regard to nitrous oxides, but this will not greatly simplify the technical problems. Better technical solutions are on the horizon, and as these are developed, the automobile engine as we know it will be phased out, perhaps by 1980^. 175

There are a number of possible successors8»10_ The rotary or Wankel engine is already in use; its production costs are comparable to a conventional engine, it uses a little more fuel (10-20%), and although its overall emissions are higher it is easier to clear, its exhaust vrth a catalytic converter because of lower nitrous oxide levels. The stratified charge engine shows a great daal of promise. It uses a modified Otto cycT? with stayed combustion: a rich fuel mixture is first introduced into the cylinder and ignited, and this rich mixture in turn ignites a much leaner mixture which could not burn evenly with conventional spark ignition. Honda, Texaco, Ford and Fiat, among others, are working on this concept8. Honda claims to have met the 1976 U.S. standards with relatively low fuel consumption and few driveability problems. The Diesel engine also shows some promise due to its low emission levels, and eventually the Stirling engine, which uses eternal combustion, could become a candidate if extremely low emission levels are required. Jhe efficiencies, costb, and emission levels of these engines are as follows1^: Stratified Conventional Rotary Charge Diesel Stirling

Fuel Cons.: Ib/hp hr .35 5 ,35 .35 45 Cost: $/hp 4 4' 5' 6' 12* Emission: 100 100 25 20 5 At present, gasoline costs about 1.6 cents per vehicle-mile for a 4,400 pound car travelling 35 miles per hour, while electrical power would cost about 2.25 cents per mile^. With the projections indicating that gasoline will continue increasing in price tnrough the year 2000 while the cost of electricity will leva! off in about 1980*>s it seems that electrical automobiles are almost inevitable in the long run. What proportion they will constitute by 2000 is difficult to predict. In summary, two basic technical changes will occur in the Canadian automobile: a reduction in size and weight, and different forms of propulsion. The fuel cost, and therefore the marginal cost of a trip, will increase as a proportion of the total cost per mile for owning and operating a car. The cost per mile might increase from 13 to 20 cents, and the cost of fuel from 25 to 50 percent of total cost. If the initial cost of the car is kept fairly stable by trading off increased power-plant cost against smaller size, the overall cost increase is acceptable. Overall, the situation might approximate that in Europe, where gasoline prices are currently about $1.50 per gallon and increasing. Cars are smaller, but there is no shortage of traffic congestion. Transit Public transit is more efficient than the automobile in its use of energy9; Mode BTU/passenger-mi 1e Bicycle 200 Walking 300 Transit 3,700 Auto 7,900 "176

iransit vehicles also preface much less pollution per passenger-mile than automobiles*!. Therefore, from an energy standpoint, transit is more desirable than the automobile. In Ontario, it is stated government policy that transit is to be encouraged relative to cars in cities, and funds for transit have been increased. Technical innovations are on the horizon, such as the magnetic-levitation Intermediate Capacity Transit System to be built in Ontario cities. However, the diesel bus is likely to remain the mainstay of transit, and due to its low emissions of pollutants relative to the automobile, especially on a passenger-mile basis, it will require fewer modifications than the latter over the next decade. The bus will also be less affected by fuel price increases, since fuel costs are a relatively small part of total operating expenses. Diesel buses will probably outlive gasoline-powered automobiles as a transportation mode. Use of electric power will increase in transit, but it is unlikely that transit will be totally electrified by the year 2000. Overall, transit will be less affected by the changes in the cost of energy than the automobile. Modal split Modal split is the term used by transportation planners for the division of trips between transit and auto. The auto currently accounts for the bulk of passenger-miles in Canadian cities and for the majority of trips. In Metropolitan Toronto it is estimated that autos accounted for about six billion passenger miles in 1969. while transit accounted for about 1.5 billion, a ratio of four to one^. For certain kinds of trips, transit is much more important: over 70 percent of people working in downtown Toronto arrive by subway or streetcar. However, for most urban travel, the auto is more popular than transit, and the reasons are fairly obvious: it offers great advantages in time saving, is more flexible, and is relatively private. It costs more, but the perceived marginal cost of each trip is often comparable to the transit fare*. It has been shown here that certain changes will occur as a result of increased energy costs: housing type might be slightly affected, automobiles will be smaller, slower, end more expensive, ar.d transit costs will increase less than autc costs. Wh3t effect will this have on modal solit? All these changes — nigher residential densities, higher auto cost, lower transit cost -- will tend to encourage transit relative to auto, reinforcing trends already evident in Toronto, for instance. T!>e critical issue is, of course, the extent of this shift: will Canadian cities be deserted of cars? There is little reason to believe so, because evidence indicates that the decision in choosing between transit and auto for urban trips is influenced more by time saving than by reasonable variations in cost, and the auto will still offer considerable time savings for most urban trips outside the central business district in the year 2000. Tne cars will be smaller and lighter, their engines will

* I/i o/erall terms, the cost of the urban auto/road system is about 8 cents per person-mile compared with 5^ cents for the transit system12. Increased ,, energy prices will affect construction and manufacturing costs for both fl modes,, ts well as operating costs. Only the latter have been considered 1 here. 177

cost more, they will cost more to run: but despite improved and expanded transit service, they will still provide most of their present advantages relative to transit. If income levels continue to rise, there will not be any sharp reduction in auto ownership per capita except perhaps in very high density residential areas with high levels of transit service. All of this is speculative, but logic indicates that an increase in energy cost will have a relatively minor effect by itself toward encouraging the use of transit. Explicit policies designed to discourage auto use, for instance higher parking rates, road user charges, and higher fuel taxes, combined with improvements in transit service, will have'more effect on modal split than increased energy costs. Even with a major shift to transit, however, urban growth rates projected to 2000 indicate that auto congestion will still be serious."!3,14 CONCLUSIONS We have shown that the future energy situation in Canada will have three direct effects on urban land-use and transportation: (i) housing mix and design will be somewhat influenced by increased heating costs; (ii) public transit will be less affected than the automobile by increased energy cost; (iii) automobiles will be smaller, somewhat more expensive, and will use a different engine type. The basic effect of these changes will be to encourage the expansion of transit. However, the auto will continue to enjoy most of its relative advantage in speed and flexibility, and will continue to be the major mode for urban travel in Canada, although transit usage will increase. Auto congestion will continue to be a problem. It is possible that by the year 2000 communication will start to be a substitute for travel,'- but, this is pure speculation. Overall, the effect of increased energy cost will be only ona of many factors affecting urban development, and not the major one. Urban planning should take into account the energy situation, but must continue to be mainly concerned with the basic characteristics of transportation and land-use. It is especially important that energy policies should be developed on an overall system basis, and not at the urban level. We have begged what is perhaps the most important question of all: even though we can pay for it, can we afford to squander energy? The urban planner may speculate on this, but he cannot decide. REFERENCES 1. Ministry of Energy, Mines and Resources, An Energy Policy for Canada - Phase I (Ottawa: Information Canada, 1973) 2. Ontario Advisory Committee on Energy, Energy in Ontario, The Outlook and Policy Implications (Toronto: 1973) 178

3. F. Stuart Chapin, Urban Land Use Planning (Urbana: University of Illinois Press, 19651 4. Toronto Transit Commission, Annual Report, 1972 5. M. Earl Campbell, "The Energy Outlook for Transportation in the United States", Traffic Quarterly, XXVII, 2 (April 1973) pp. 183-210 6. Fortune, June 1973, pp. 118-123 7. Road and Track, October 1973 8. Environmental Science and Technology, Vol. 8, No. 7 (August 1973) pp. 688-689 9. Enc Hirst, "Energy-Intensiveness of Transportation", Transportation Engineering Journal of the ASCE, Vol. 99, No. TE 1 (February 1973) pp. 111-122 10. William Savery, "Future Energy Sources for Transportation", Traffic Quarterly, XXVI, 4 (October 1972), pp. 485-500 11. Metropolitan Toronto Transportation Plan Review, Report No. 18, Strengths and Weaknesses of Public Transport (March, 1973) 12. Metropolitan Toronto Transportation Plan Review, Report No. 12, Transportation Finance, Part 2 13. N. H. Lithwick, Urban Canada: Problems and Prospects (Ottawa: CMHC, 1970) 14. J. W. MacNeill, Environmental Management (Ottawa: Information Canada, 1971) 15. R. C. Harkness, "Communications Substitutes for Intra-Urban Travel", Transportation Journal of the ASCE, Vol. 98, No. TE 3 (August 1972) pp. 585-598 179

DISCUSSION OF SESSION II

A question was addressed to M. Real Boucher, the Sessional Chair- man, by Mr.P.L. FOURNIER {National Energy Board): Given the rapidly rising price of oil on the international market, and given the probability that the OPEC countries will restrict production growth and possibly use oil as a political weapon against the West, can you comment on the stated -preference of the Government of the Province of Quebec to continue to rely on offshore oil, as opposed to domestic oil, which should be a more secure and price-stable source of oil (in particular its opposition to the extension of Interprovincial Pipe Line)?

M. BOUCHER: The Province of Quebec still intends to rely partly on offshore oil as opposed to domestic oil since its long-term demands cannot be met by the short-term Albertan reserves (12 to 14 years) and also because offshore oil as an alternative source will provide an adequate form of competition which, in the end, is the most effective way of controlling prices.

PROF. H. McQUEEN (Dept. of Mechanical Engineering, Sir George Williams Univ., Montreal) to Dr. Dagher:

WJtat optionc, are open to the United States if ina-eac i.>: ..• numbers of Arab nations cut off the export* of oil to that country? Please comment from the short- tc-rm a ?..•.;' long-term points of view. DR. DAGHER: In the short term, the possibilities open to the United States depend on what availability in the world pattern of supply is feasible within newly imposed constraints, what savings in energv consumption can be achieved and what substitutions between energy fcrms (for example, coal for oil) can be implemented.

In the longer term, substitution of other forms of energy becomes much more feasible and therefore significant. MR. E•E. ROBERTSON (The Biomass Energy Institute Inc., Winnipeg) to Dr. Dagher: Do you foresee any significant impact on Canadian energy industries from the proposed §10 billion 5-year crash energy research and development program 180

ernbracinc all forms of renewable opposed to non- vens'CiL! ic resources?

DR. DAGHER: There is, of course, always an element of uncertainty in the results that can be derived from any research program. However, certainly over the next decade and probably also over the next two or three decades, the demand for Cr-ada's hydrocarbon resources is not likely to be significantly affected by the results of such research. So I do not foresee any adverse impact from this research and development on Canadian energy industries and possibly a beneficial impact from, for example, coal gasification/liquefaction, transportation research.

DR. R.E. FOLINSBEE (Dept. of Geology, University of Alberta) to Mr. Lester: What is the long-term ALCAN security of an electricity source like Kitimat? Please comment on this in the light of the policies of Premier Barrett and of electricity shortages fcr a growing population.

MR. LESTER: It is not logical to suggest that the B.C. Government would consider measures ivhich would endanger the viability of one of the province's most important industries, one which provides employment for several thousand people and supports a large industrial community not only of aluminum production but also pulp and paper. Moreover, since 1966, the Kemano-Kitimat complex has been the principal power supply source for a large section of northwestern British Columbia, providing electricity to this isolated portion of the B.C. Hydro system much more economically than otherwise possible.

DR. W.B. LEWIS to Mr. Lester:

./ suggest thai your M the United Makes. The uorLl hae, no nnai of brnrdvr reuc tons for it:; nuclear pouev. Nuclear energy r'i:al- costi.) arc still falling gveally lolthoul breeders. MR. LESTER:

Whether nuclear costs are actually falling today seems rather conjectural, but I would certainly c:gree, and so stated in the paper, that nuclear power costs would tend to at least level out at a plateau below alternative energy costs for many applications. I would also agree that breeder reactors are not required to achieve this happy economic result since, in any case, nuclear fuel costs are but a small part of the total nuclear power cost. However, and with all due respect to 181

Dr. Lewis' long and logical espousal of the CANDU natural uranium reactor, most of the nuclear power world seems convinced, rightly or wrongly, that a true breeder reactor will be necessary to stretch out the economically available supply of U-235. Having regard to development work in Britain and in France, and to the forthcoming $5 billion effort by the U.S.A., it would appear that we are going to get breeder reactors whether we need them or not.

PROF. H. MCQUEEN (Dept. of Mechanical Engineering, Sir George Williams Univ., Montreal) to Mr. Lester: What plans should the aluminum industries have for conservation of energy through the increased use of recycling of aluminum? This would make electricity available for other purposes. MR. LESTER:

Recycling has always played a prominent role in the aluminum industry, and secondary aluminum, so-called, already accounts for about one-quarter of total metal supply. Only 5% as much energy is required to recycle aluminum as to reduce new metal from its ore. In the face of mounting energy problems, the industry has been accelerating its efforts in this direction.

DR. A.D. SCOTT (Dept. of Economics, Univ. of B.C.) to Mr. Lester: You mentioned that one result of the rising energy prices would be a loss of markets by those industries that are energy-intensive to other products that are not energy-intensive. Which Canadian industries arc likely to lose out in this way?

MR. LESTER: T. don't believe we should exaggerate this possibility inasmuch as the competitiveness of most industries depends more on logistical market factors than on energy. However, if energy costs rise dramatically more than the price level of all commodities in general, such industries as synthetic fibers (competing with natural fibers) and metals (where they compete with wood and plastics) could lose ground. Canadian industry, taken as a whole-, would only lose out if Canadian energy cost increases were to out- strip those elsewhere but, as we noted, this is not likely to be the case.

MR. C.R. RIOPEL (Acres Consulting Services, Vancouver) to Mr. Lester

If Arab countries cut off oil supplies to the U.S.^ can we expect Venezuela and other non-Arab UP3C countries to move to fill the gap? If so3 do you think that this coulri cause the break-up of OPEC as now constituted? What vnuid be the effects on oil prices if OPEC breaks up? 182

MR. LESTER: If Arab oil supplies to the U.S.A. were cut off entirely and remained cut off, and I believe this to be highly unlikely, the 5% to 10% shortfall that would immediately occur in the U.S.A. total oil demand could conceivably be met by increased production elsewhere, particularly Iran. However, in the longer run, I would expect that the problem would be met by an even greater accelera- tion in the development of alternatives and substitutes, ^oubined with some rationing. As to the ultimate fate of OPEC, and the effect its possible demise would have on oil prices, such a prediction requires more courage than I can muster.

MR. G.D. COATES (Luscar Ltd., Edmonton) of Dr. Downing: Could Alberta's proposed natural gas rebate ("two-price") system actually stimulate the development of an expanded petrochemical industry in that Province?

DR. DOWNING: It might. The tremendous growth of the U.S. petrochemical industry on the Gulf Coast was certainly due in large measure to a government action — that is, regulations holding down the price of natural gas in interstate commerce. The effect was to hold down the price of natural gas higher components too. MR. W. DUNNINGTON (Du Pont of Canada, Montreal) to Dr. Downing: A. Are the following assumptions correct? (I) Liquids from taruands rhould cost less than liquid a from coal

(ii) United States coal is closer to Canadian markets than is Canadian coal (Hi) The United States will develop, at great expense, technology for making liquids from coal b. Would you agree that Canada should not do much work on liquids from coal? DR. DOWNING:

A. (i) Yes, usually. Less treatment needed, but more material needs to be moved. New coal technology might chancye the picture. (ii) True east of Great Lakes, (iii) I certainly expect so. B. At this time, I agree. The picture may change as Alberta oil production declines. 183

MR. W.M. CAMPBELL (Atomic Energy of Canada Ltd.) to Dr. Downing:

What factors are missing in Canada that prevent the amalgamation of chemical companies3 as happened in France and elsewhere? DR. DOWNING:

Any political driving force; in fact with present combines laws, these are obstacles.

PROF. H. McQUEEN (Dept. of Mechanical Engineering, Sir George Williams University, Montreal) to Dr. Downing:

What will be the effect of the oil export tax on the price of Canadian petrochemicals relative to that in the United States? DR. DOWNING:

It is too early to say. You would expect it to make petrochemical feedstocks relatively cheaper in Canada.

DR. Wm. VEDDER (General Electric Co., Schenectady, N.Y.) to Dr. Downing:

(i) Do you believe that a "methanol economy" might be possible : (ii ' Woul-l you discuss the economics of gas liquefaction v?i-u*.: conversion of gas to mcthanol (•Hi) At what distance between the source of gas end the consumer does methanol become more attractive'-

(iv) Is methanol a more desirable fuel? (v) Can methanol be made from coal via the gas phase or direct, lit': DR. DOWNING: This area is under intense discussion and development and conclusions are not yet clear. Liquefaction is probably cheaper today than conversion to -methanol. Methanol is a perfectly good fuel. To make it from coal you would gasify the coal first-

DR. BEN HOGG (Univ. of Manitoba, Winnipeg) to Dr. Pill:

With a email population and a large land aveas except for Toronto, Montreal and Vancouver,, why arc we in Canada concerned with anti-pollution devices in our cars? Is there any legislative deadline (as in the U.S.A.) on auto anti-pollution devices in Canada? 184

Is it not rrure realistic in Canada to conoentr'ate on industrial anti-pollution devices?

DR. PILL: We are concerned with anti-pollution devices in Canada for the same reasons that the United States and Europe are concerned: air pollution in the cities. Toronto, Montreal and Vancouver suffer from it less than perhaps the most striking examples south of the border, such as Los Angeles. However, the need is there in Canadian cities, and it is simply a question of the degree of control. The 197 3 Canadian standards, as set by the Canadian Motor Vehicle Safety Regulations, led to a 70% reduction of exhaiist emissions on a new car. It can be argued (see Bus and Truck Transport, April 1973, pp. 19-37 for a comprehensive presentation of the case) that not much more reduction in emissions is required. The 1976 United States standards (originally their 1975 standards) are very stringent, and in July 1973, the Minister of Transport and the Minister of the Environment announced that Canada's standards for 1975 would be less strict. The net result is that Canadian cars will have to have about the same modifications to carburetion and ignition as the 1976 U.S. cars, but will not require the catalytic converters of the latter.

1 feel that cars sold in "clean air" areas should be allowed to continue with the 1973 standards, but this presents numerous logistic and manufacturing problems. As for industrial anti- pollution devices: of course, but not at the expense of control of automotive pollution. In many of the smaller on3-industry cities, industrial pollution Jiay be the most serious, and should receive priority. But I think both sources should receive attention.

DR. D.G. STEPHENSON (National Research Council) to Dr. Pill:

Would you please comment on the possibility of IJ in Lria L Heating having a significant impact on the way urban areas a^e developed,

DR. PILL: Research has indicated that District Heating, which as I understand it is the use of a central heat-generating plant using hydrocarbon fuel, offers an increase in efficiency on an area- wide basis. It would seem to be most useful in high-density developments, although it apparently works also in medium-density. The basic question with regard to its viability is: can it continue to offer -fficient savings to make hydrocarbon fuels competitive with eit ricity as the prices of the former rise? With use of oil or natural gas it is highly unlikely, but with coal there is certainly some promise. If it is viable, District Heating probably would not have a major impact on urban form: it would be just another utility. If it offers sizable savings, a District Heating plant might increase land prices in its 185 service area. More research and pilot projects are certainly indicated in this field. DR. I.E. EFFORD (Science Council of Canada) to Dr. Pill:

lour comparison of auto and rapid transit energy use differed from published accounts which suggest a ratio of 10:1 rather than 2:1 (Healey, 1971). Why is this? DR. PILL: The figures in my paper are from Hirst's article, as cited in reference number 9. Such a calculation is dependent on a number of factors: load factor, subway/streetcar/diesel bus mix, and line-haul versus feeder service. The figures cited for energy- use in transit are probably high, and they would be lower for Canada than for the U.S. In any case, there is no doubt that transit is more energy-efficient than the auto.

DR. EFFORD to Dr. Pill: Did you include the energy costs of road com? iruction and maintenance in your estimates of the cs^r's energy, consumption? Furthermores there is the difference between the energy used in the actual manufacture of the cars and buses or trams which would bias the figures more heavily in favour of bus and transit system:-. Was this done? DR. PILL:

Neither of the factors you introduce was considered in the paper. Perhaps they should have been, but the point of view taken was that of the consumer, and the issue was the degree of impact of increased energy cost on his travel behaviour. The cost of construction and manufacture in energy terms are germane to decisions by government and industry, although, of course, they will affect the consumer in the long-run. In the decisions on government policy between roads and transit, it is likely that factors other than energy will carry most of the weight. In Ontario, for instance, there is a provincial government policy encnuraginq transit which is not based to any great extent on energy considerations.

On a more substantive note, Richard K. Pefley, in a paper entitled, "Reducing Energy Demands," presented at the Conference on Transportation Horizons: Rebuilding Urban Environments at Berkeley on September 24, 1973, stated that transit construction involving subways is more energy-intensive than road construction. 187

SESSION III

PROSPECTS OF TECHNOLOGICAL CHANGE

Tuesday, 16 October. 1973, a.m.

Chairman W.B. LEWIS, F.R.S.C. Deep River, Ontario 139

THE NUCLEAR ENERGY INDUSTRIAL COMPLEX AND SYNTHETIC FUELS

W.B. LEWIS, F.R.S.C.

Although concern about coal resources was oiscussed in the last century conflicting views were commonly expressed up to 1950. In fact, the first broad and serious study bringing together forecasts of population and the use of coal, oil and natural gas was made by Palmer Putman only 20 years ago in 1953 for the U.S. Atomic Energy Commission and published as "Energy in the Future" by Van Nostrand. It was clear that the world's fossil fuel resources were being used up much faster than they were being formed. In fact the market operation depended on exploration and new discoveries, while knowing there ir.ust be a limit. For a long time estimates of prospects, or discovered reserves kept increasing. But now human nature indulges in some gloating over the coming prospect of a general shortage and high prices. l.'ithin the last 20 years ne have come to realize that no such prospect faces nuclear fuel. It is even nonsense to say, as some have, that man's enjoyment of cheap energy has now passed forever. It is not even correct to argue that breeder reactors or nuclear fusion will be necessary to get down to such a low cost. bnderstandinr this is basic to understanding the topic of this session namely the "Prospects of Technological Change". If we direct our attention and actions oroperly the prospect is to have energy costing say 3 mi 11/kWh, or $l/MBtu in 1972 dollar values in effectively inexhaustible amount as long as we allow technology to develop. Of course if we stop or lose our heads mankind is likely to perish. Even 3 rnill/kWh may be an unnecessarily high price, the exact figure depends on how much foresight we can bring to bear on our actions. If we keep scrambling to discover and bring to market oil from remote and difficult sites not only the price but the real cost would go higher. So too if we continue to build and operate nuclear power stations as we do now, even those like the successful Pickering. 190

Although the first general study on the basic idea of the nuclear energy industrial complex was published to the world 5 years ago, there seems to be little effort in the western world towards the needed foresight and technological change to put the idea into practice. The essential key is to plan and build both nuclear reactors or generating stations and also segregated nuclear fuel processing and management plants on appropriately related sites each on a sufficient scale such as 100 million kilowatts, in one interacting complex. Probably it is first necessary to educate the political, finance, business and technical worlds to understand the basic principle of economics that J.K. Galbraith calls the paradox of savings The supply of Capital and the supply of savings are aspects of the same thing. To quote Galbraith (1967) The Mew Industrial State p. 45 "Here is the paradox of savings: the steps which insure that they will be used serve also to increase their supply. The more effectively they are offset by investment the higher will be the income and the more savings there will be. 'Most communities in the past were limited in their progress by the savings they could extract from their meager product to invest in better methods of production. The same is true of poor nations today. The rich nations must also have savings to expand. But what is called economic progress here depends less on the supply of savings than on the effectiveness with which employment of a more than ample supply is insured. Not a shortage of savings but a recession resulting from the failure to use all available savings is the specter that haunts all policy makers. For investment to exceed savings, at least in peacetime, is thought exceptional. This tendency of savings and thus of capital to abundance, abundant use notwithstanding, is a matter of penetrating historical and social con- sequence . . ." The expansion and even the maintenance of the fossil fuel industry demands a continuing supply of capital or savings, because a locally finite resource is being used up; so mines have to be extended or now sites discovered. New pipelines, railways, etc. to link the source to the market are also needed. For nuclear power;, fuelling costs can be much lower but the need for capital is much the same 191

to build generating stations and to transmit and distribute the power. The prospect of technological change arises because the unit cost of energy from fossil fuels must, in general, rise despite some advances in technology such as unit trains, slurry pipelines, and increases of size of fossil fuel fired electric generating stations. On the other hand the unit cost of nuclear energy can fall a very long way. But, even if it stayed constant, at some point the cost of fossil energy would rise above it and make it profitable to introduce a technological change, in particular producing synthetic liquid or gaseous hydrocarbon fuel to carry on serving the market. The basic idea is not new and I may quote from Palmer Putnams 1953 book page 166 under the heading "Synthetic Fluid Fuels" "The mounting preference for fluid fuels has been described. In 1953 in the United States they are carrying about 57 per cent of the load. By 1960, if the preferences continue to be met, the proportion may be 67 per cent; and by 1975, 75 per cent. 'Rising costs of the discovery and refining of crude petroleum, and decreasing costs of synthetic fluid fuels in pilot-plant quantities, have brought the two within sight of each other economically. More important: synthetics give promise of using less steel, per barrel-day of production, than the petroleum industry uses." As I have indicated the study in 1966-68 of the Nuclear Energy Agro-industrial complex carried forward that basic idea indicating that as the cost of nuclear energy comes to be reduced it would progressively initiate technological change in several major industries and finally could fvlly substitute synthetic fluid hydrocarbon fuels for the petroleum products. At the present time the downward trend of the cost of nuclear power has been temporarily halted at a point where it is just competitive with fossil fuel generated electricity. In this use and circumstance it is locked in with two current economic facts the high interest rate on borrowed capital and the escalation of costs associated with both high interest rates and 192

devaluation of currencies. Electric utilities financed in this way cannot promise anything but a rise in the cost of power. We should note, however, that not all electric utilities are necessarily financed in this way, and low interest rates such as at one time available for example to the Tennessee Valley Authority make a very large difference to any prospect. Moreover the savings that have to be applied as capital way be directed to be derived otherwise. Governments with powers to tax, may in other words compel savings from other activities or even from the utilities themselves. What governments cio with money lies firmly in the political field where differing views can be held passionately. To introduce a rational element, it is necessary to point out the prospects of technological change as well as the prospects of technical conservatism. The unit cost of electricity, the cost per kilowatt-hour from nuclear energy will fall as the industrial complexes formed by generating stations and fuel reprocessing plants are increased in capacity. If large capacities such as 100 million kilowatts are planned for, the initial costs are necessarily high but not beyond the range of savings that can be attained in highly industrialised countries. Canada presented the advantages of adopting a thorium fuel cycle on a large scale with its CANDU reactors at the 4th United Nations Conference on the Peaceful Uses of Atomic Energy two years ago. From what has been said above it is clear that the actual cost depends on the scale adopted and also on the interest rate applicable. The following table relates costs of energy to those of synthetic fuels excluding delivery costs and costs of the carboniferous source whether carbon or limestone. In other words the table shows the cost contributions from the energy conversion. 193

CONTRIBUTION OF ENERGY COST TO COST OF SYNTHETIC FUEL ASSUMED COST OF ELECTRIC ENERGY INCLUDING ELECTROLYTIC CELLS 2.5 mill/kWh 5.0 mill/kWh ASSUMED ENERGY FOR PRODUCING 2000 STD 240 kWh 270 kWh 240 kWh 270 kWh CU. FT. HYDROGEN COSTING 604 67.5

FR0M .METHANE 497.5 120.6 135.7 241.2 271.4 LIME- {ETHANE 505.9 118.6 133.4 237.2 266.8 STONE (OCTANE 507.6 118.2 133.0 236.4 266.0 AS 10.000

FORECAST WORLD ELECTRICAL CAPACITY OF NUCLEAR POWER STATIONS ,-63% I (raclutting fftiml 2.000 •52%

1.000 '27%

Kj&r. UNDER CONSTRUCTION OR COMMITTED AS OF JUNE 1973 • 13% 200

100 8% NUCLEAR — COMMISSIONED ELECTRICAL UNDER CONSTRUCTION INSTALLED & COMMITTED CAPACITY -- FORECAST GW 20 2.2% OF TOTAl ELECTRICAL CAPACITY

1 6IGAWATT " 10° KILOWATTS All Promdinp IAEAJ1971 - STI TUB/361 • I SPii'U. PJP" SM IK?

I960 1965 1970 1975 I9B0 1985 1990 1995 2000 YEAR

FIGURE 1 — Forecast of world electrical capacity of nuclear power stations. 195

FISSION, FUSION AND FUEL ECONOMY by A.J. MOOPADIAN. F.R.S.C. Atomic Energy of Canada Limited, Chalk River

INTRODUCTION

Nature has given man abundant resources of Uranium235, U238, Thorium, and the ability to produce electricity. With these basic ingredients, the future of mankind and the options which he chooses to exercise will not be limited by the supply of energy. Even with a world population of 15 to 20 billion people and energy requirements twice that of the current North American standards, there is no apparent barrier to supplying mankind with sufficient energy into the foreseeable future.1*2 This is no scientist's dream. With current technology at the commercial stage cf development, and the elasticity of uranium supply with price, man's fuel supply is secure for hundreds of years. Evolutionary developments of today's concepts, based on proven scientific principles and credible technology, expands the security of energy supply to thousands of years. For those who are concerned about a future beyond this, there is always the hope for fusion.

Given these resources, we have a plethora of options. The Geneva Conference of August 1955 opened the book on the peacetime application of nuclear energy for all who cared to read and participate. Since that time many concepts have failed to meet the test of practicality and fallen by the wayside. A few have been developed to commercial status and have started a technical revolution in central electricity generating power stations. Others are in an advanced state of development and are at the threshold of a test of viability. Still others are awaiting a test of scientific feasibility. The purpose of this paper is to review the current status of nuclear power stations, examine the factors which are apt to influence future developments and examine impending developments in the light of these factors.

Figure 1 shows the nuclear capacity now installed, that committed, and forecasts for future stations. As of June 30 of this year, 262,974 MHe of nuclear capacity was in operation, under construction or on order throughout 26 countries.3 All of this capacity is based on the fission process. It helps to put this number in context by remembering that it requires about 50,000 MWe to service the whole of Canada with electric power.

There are but three general types of reactors which have achieved commercial status in the western world, By that 196

HEAVY WATER STEAM STEAM MODERATO R GENERATOR r=Z- STEAM

WATER MODERATOR «. •r TUBES- & COOLANT REACTOR

PUMP WATER BOILING WATER REACTOR HEAVY WATER REACTOR (LIGHT WATER)

STEAM STEAM GRAPHITE GENERATOR MODERATOR WATER MODERATOR & COOLANT

STEAM GENERATOR

WATER PRESSURIZED-WATER REACTOR BLOWER (LI1HT WATER) GAS COOLED REACTOR

FIGURE 2 — Nuclear power concepts at commercial stage of development. 197

I mean that they are purchased By ut'Tlftfes on a strictly commercial basis with sufficient confidence that the grid is dependent on them for poorer supply. They are characterized in the trade as light water reactors, ga: cooled reactors and heavy water reactors [see Fig. 2). All have the follow.ng features in common: (1) They use uranium as a primary fuel. (2) They are classified as "thermal" reactors, i.e. a moderator is required to slow down the fission neutrons which emerge at 2 MeV to thermal energies. (3) They produce electricity by generating steam to drive a conventional turbo-generator unit. (4) All breed plutonium by the reaction of spare neutrons on the fertile material U238. LIGHT MATER REACTORS The U.S. light water reactors were an early arrival on the commercial scene. The submarine reactor program gave a highly pertinent base for the entire reactor system. The existence of large enrichment facilities in the United States combined with a dependence on thermal generation stations, were important factors in getting these reactors quickly off the mark. Because of this early commercial entry and the establishment of a large U.S. market, the vast majority of commercial reactors which have been committed throughout the world are based on this concept. Probably the most important characteristic of the light water reactors is that they require enriched uranium as a fuel. Natural uranium, which contains only 0.7% of the fissile isotope U235 cannot be made to react in such an environment. Typically, commercial plants of this type use uranium which is enriched to levels of about 2.2 to 3.5% U235. Since enriched uranium is rather expensive, the economic optimum drives the designer to use as high a power density as possible to alleviate the inventory cost. The use of light water for a moderator dictates that the fuel be rather closely packed in order to avoid excessive loss of neutrons by capture in light hydrogen. This then drives the designer to the pressure vessel concepc. The pressure vessels used in light water reactors are no mean achievement. A typical 600 MW PWR unit requires a pressure vessel with diameter 4 m, length 1? to 13 m and wall 27 cm thick.

The BWR pressure vessels tend to be larger but since they operate at lower pressure, the wall thickness can be somewhat rejuced. The Millstone I vessel, for example, is 5.7 m in internal diameter, 19.6 m long, with a wall thickness of 14.5 cm. The combination of enriched fuel operating in a pressure vessel makes it extremely difficult, if not impDssible, to 198

fuel the reactor while at power. All such reactors are based on off-load refuelling. Refuell>.g schedules vary but generally speaking require a shutdown of 3 to 4 weeks duration at inter- vals of 12 to 16 months. GAS COOLED REACTORS The second cla3~ of commercial reactor, championed by the U.K., is characterized by the use of graphite as a moderator and carbon dioxide as a coolant. The first generation stations were called the Magnox stations5 and they deliver almost all nuclear power now feeding the U.K. grids. Graphite is not as efficient a moderator as water, and therefore a larger volume is required to slow down the neutrons. The use of carbon dioxide has both a positive and a negative aspect. High quality heat can be extracted from the core, e.g. the Wylfa station has an outlet coolant temperature of 402°C as compared with about 300°C for the water-cooled reactors. However, gas is not nearly as good a heat transfer medium as water, and hence the designer must cope with handling large volumes of gas in both reactor and boiler. This, in turn, leads to higher capital costs. The Magnox stations use natural uranium metal clad in a magnesium alloy (hence the name Magnox). These first-generation gas- cooled stations have been reliable performers and for several years held the record for total power generated.

A second generation of gas-cooled reactor has now been committed in the U.K.; the so-called Advanced Gas-cooled Reactor (AGR).6 it, too, is graphite-moderated and cooled by carbon dioxide. However, to allow the fuel to operate at higher temp- e-atures, stainless steel clad uranium dioxide is used as a fuel. This, in turn, has required the use of enrichment. The reactor is still very large by PWR standards (20 m I.D. x 17.8 m high). Indeed, the pressure vessel problem could have proved to be intractable had it not been for the ingenious application of the pre-stressed concrete principle. There has been some difficulty in commissioning the first of these AGR stations and therefore little operating experience has been accumulated. All of the commercial gas-cooled reactors are designed for on-powar fuel ting. The large pressure vessel and the spreading out of the fuel by the graphite moderator makes this an easier task than in the case of the Light Water Reactors. Although the gas reactors were the earliest commercial stations in operation, very few have been committed in countries other than the two major sponsoring countries, France and Great Britain. Tndeed, the utilities of both countries are busy looking at alternatives for the next generation of stations. 199

HEAVY WATER REACTORS The most important event on the commercial scene since nuclear power was first introduced is the dramatic success of the 2000 HWe Pickering power station.7 Pickering is important, not because it is a Canadian achievement, but rather for the world at large, it removes all practical and commercial barriers to the full exploitation of the heavy water moderated concept. Pickering is a member of the CANDU family of reactors, the so- called PHW variant (for P_ressurized tteavy W_ater cooled). Heavy water is the most efficient moderating medium which nature has to offer. It has captured the imagination of reactor designers the world over8 since the inception of the atomic era. Its overwhelming merit is that it allows very efficient utilization of fission neutrons. As a result, fuel cycles can be conceived which will not only allow the use of natural uranium, as in Pickering, but also those which .an greatly extend the resources of nuclear fuels available for economic exploitation. Canada is the logical champion of this concept. During the last war she had been assigned the task of producing Plutonium from heavy-water moderated reactors. NRX and subsequently NRU were built principally for this purpose. The technological roots date back to 1945. However, it is a long step from recognition of potential to the proof cf commercial viability. The trick has been to prove practicality without the loss of potential. In this regard the choice of natural uranium for fuel has been a key factor in disciplining the program to make best use of the neutrons which the use of heavy water saves.'0 Several important achievements have been required: (1) The development of a reliable fuel assembly containing a minimum of parasitic material capable of being mass produced at low cost and achieving burnups in the order of 10,000 HWd/tonne U.H (2) The development of a pressure tube of low neutron capture cross section and long life under irradiation.!2 (3) The development of a reliable on-power fuelling machine capable of making and breaking high pressure seals several times a day. (4) The development of reliable heat transport and moderator systems which minimize the inventory of heavy water am) its potential for leakage and loss. (5) The development of engineering, manufacturing and construction skills that allow the entire system to be competitive in today's commercial environment. 200

TABLE 1 FISSILE INVENTORIES FOR TYPICAL COMMERCIAL REACTORS (600 MWe] Reactor Type Fuel Type U2 35 Inventory U235 Inventory tonne worth* CANDU-PHW Natural 0.61 $1 .73 X 106 Light Water PWR Enriched 1 .26 $12.4 X 10e BWR Enriched 1 .82 $17.9 X 106 Gas Cooled Magnox Natural 4.30 $12.5 X 106 AGR Enriched 2.43 $17.7 X 106 *Fabrication Cost Excluded Based on $8.00/lb U308 Separative Work Cost $38.50/kgU

TABLE 2 COMMERCIAL REACTORS AS PLUTONIUM BREEDERS Reactor Type Grams of Plutonium in Spent Fuel per Gram of U235 Consumed CANDU-PHW 0.57 Light Water PWR 0.28 BWR 0.31 Gas Cooled Maanox 0.34 "AGR 0.23 201

Table 1 graphically illustrates how successfully neutron efficiency has been conserved in the CANDU-PHW (the Pickering type reactor). The core fissile inventory is between a factor of 2 to 7 lower than that required by any of the other commercial concepts. The neutron efficiency of the system is such that natural uranium fed in at a concentration of 0.71% jj235 emerges in the spent fuel at a concentration of 0.18% U23S; a value lower than the tails assay from diffusion enrichment plants. In short, the enriched reactors waste more of nature's U235 before the fuel enters the core than Pickering does after the fuel has been used. The fuelling cost for Pickering is between 0.7 and .88 mills/kWhe, 50% to 100% lower than its competitors; and this without any claimed credit for the plutonium values in the spent fuel. Yet another illustration of the neutron efficiency of the CANDU-PHW is given in Table 2. Plutonium is as good a fissile material as U23S. Hence its production can be considered a replacement for the consumption of U235. FACTORS WHICH WILL AFFECT THE COURSE OF DEVELOPMENTS OVER THE NEXT 20 YEARS Ca) Worldwide (Canada is no exception) the anticipated doubling time of electrical capacity is about ten years.'3 For a number of economic, strategic, environmental and political reasons, nuclear capacity is expected to double faster than this. Grids now accepting 500 MWe units will in twenty years take 2000 MWe units. Already several commercial units have been committed at about 1200 MWe. (b) Canada is uniquely gifted with an abundant supply of cold cooling water. This is not generally true for the rest of the world. Power plants will probably migrate to the sea shores and systems capable of operating efficiently with warmer sink temperatures will become more attractive. (c) Until the advent of nuclear power, the only fissile isotope available to man was U23S. Since, as I indicated earlier, all commercial reactors breed plutonium, a major new resource of fissile material will become available tsee Table 3). Its.optimum use will command a great deal of attention. (d) The inventory of uranium accessible to man is very large. It is estimated^-that 2 x 1Q12 tonne is available within a aile of the earth's surface and 4 x 109 tonne in the oceans. The earth's inventory occurs in a continuum of concentrations and so the supply will be determined by price. At 1973 prices (about $6.S0/lb U308), the uranium supply industry is not overly stimulated to develop proven reserves. 202

TABLE 3 14

WESTERN WORLD PRODUCTION OF PU

Year Tonne/Year

1972 3 1980 60 1985 200 203

It is reasonable to expect that prices will rise as forecasts are converted to firm orders. It is worth noting that even with present day Pickering technology, the price of uranium could rise to $100/1b U308 before the fuelling cost would match that of a coal-fired station in Ontario using low sulphur coal. At these levels one could seriously contemplate sea water extraction.16 (e) The question of enrichment supply and cost is extremely important. All enrichment plants now operating in the U.S., the U.K., France and the Soviet, were built for military programs and their costing is somewhat confused. As yet, no uranium enrichment plant has been built on a fully commercial basis. It has been disturbing to utilities that the price for separative work has increased from $28.70/SWt" in February 1971 to $38.50/SWU effective August 14, 1973 with a built-in provision for a 1% increase every six months beginning January 1974. By 1980, at the latest, new enrichment capacity will have to be in production. In August of this year the USAEC released a study!? of thp cost of enrichment from a new diffusion plant unconfused by military financing. The study indicated that a separative work unit would cost $51.08 to $64.91 depending on whether the plant was publicly or privately f .ianced. The same study indicated that the new centrifuge technology would result in a significant saving and could produce a separative work unit at $38.17 to $51.44 under comparable financing conditions. However, it will probably require 10 more years before suf- ; ficient confidence is generated in the new technology to I warrant the commitment of 1 to 1% billion dollars needed to I build the required capacity. i (f) The introduction of a new concept of nuclear power plant I has a great deal of momenturr to overcome. The investments i are large. Single decisions seldom commit less than ! $300,000,000, and must be made at correspondingly high con- i fidence levels. The development of a national nuclear I infrastructure Is itself a time-consuming and costly propo- | sition and tends to be oriented to a specific reactor type. I It is highly improbable that new concepts will sweep aside | those now firmly established. If proven of sufficient I worth, they will be introduced in conservative and orderly 1 fashion. S OPTIONS OF COMMERCIAL SIGNIFICANCE WHICH CAN DEVELOP I OVER THE NEXT TWENTY YEARS g. -.—.— ••, i.. ,..n.i. ..i- n. . MM,.i.,i ,,.„,.. .,, .1, , i S Light Water Reactors - Light water reactors are not apt to change | significantly over this period of time. They have already gone I through two or three generations of improvements and are rather high on the learning curve. However, their momentum ensures that many more will be committed over this period. As uranium ro o

STEAM TO TURBINE STEAM TO TURBINE. STEAM TO TURBINE STEAM DRUM^ REACTOR STEAM PRESSURE STEAM STEAM/WATER MIXTURE | TUBES GENERATOR FUEL- FUEL FUEl

HEAVY WATER MODERATOR HEAVY WATER WATER FROM HEAVY WATER PUMP WATER FROM MODERATOR CONDENSES MODERATOR CONDENSER WATER fROM PHW CONDENSER BLW OCR IPressurisod Hoavy Water) {Boiling Light Water) (Organic Cooled Reactor)

FIGURE 3 — Variants of the CANDU concept in an advanced state of technological development. 205 and separative work costs increase, the light water reactors will become less and less attractive. Already a good deal of work is being done on developing the recycling of plutonium to partly offset the cost of enriched uranium. Over this period there will be a growing incentive for utilities to explore alternative options less sensitive to uranium supply and enrichment uncertainties. Gas-cooled Reactors - The next major step on the horizon is the high temperature gas-cooled reactor under development in the U.S.. the U.K. and Germany. The concept is based on the excellent work which was done on the Dragon project. It is a significant departure from the AGR. Helium replaces carbon dioxide as coolant and gas outlet temperatures in excess of 700°C are being considered. The fuel will be based on the Dragon coated particle development. At the moment, the U.K. program is in a state of indecision and the most important hard development is the commissioning of the Fort St. Vrain plant in the U.S. This is a 330 MWe demonstration plant which is expected to come on line later this year. Despite the high temperature of th- cool- ant, power will be generated through a conventional steam cycle. The reactor type is of interest because it offers the prospect of utilising U233 bred from thorium. The potential for high thermal to electric efficiency will be attractive to utilities needing inland stations short of cooling water. The development of reliable high performance gas turbines would allow future generations of these reactors to operate on a highly efficient closed cycle. The technological problems are not insignificant. At such high temperatures most reactions allowed by thermo- dynamics are apt to take place quickly.

Heavy Hater Reactors - One can conceive of CANDU reactors which are cooled by everything from heavy water, as in Pickering, to high temperature gas. However, only three variants are in a sufficiently advanced state of development that they could be considered as serious candidates for commercial application within the next 20 years. These are shewn schematically in Fig. 3. (a) A CANDU PHW - The Pickering and Bruce designs do not exhaust the development potential of this variant. There is significant scope for development of a higher power output per channel by the development of stronger zirconium alloys for pressure tubes and alternative fuels. One of the most interesting prospects on the horizon is the possibility of using uranium silicide as a fuel to replace uranium dioxide. Such a fuel is now in an advanced state of development in our laboratories and promises to offer the power plant designers a significant improvement in power output from a given physical size of core. It also holds promise of giving even lower fuelling costs than now obtained with conventional uranium dioxide fuel. There is also a known 206

prospect of recycling plutonium back into such systems at the price of complicating the present simple, once through, fuelling cycle. (b) CANDU BLWs - The BLW variant is characterized by the use of boiling light water as a coolant. A 250 MWe prototype station (Gentilly I) based on this principle has been commissioned at Trots Rivi&res. Note that it operates on a direct cycle. It promises a significant reduction in the capital cost, but does so by encroaching on the fuel economy of the system. The introduction of this concept would be favoured by continuing good experience with Gentilly I, combined with a continuing increase in interest rates. Since the principal asset of the system is that it offers potential for capital cost reductions, it is a logical system in which to consider the recycle of plutonium. A study is underway to determine the prospects for such a concept. (c) CANDU OCR - This variant of the system uses a low vapour- pressure oil as coolant. Its merit is that heat can be extracted from the core at 400°C at significantly lower pressures than obtains for water-cooled reactors. It therefore offers the possibility of a significant improvement in thermal to electric efficiency (between 35 and 40% net station efficiency). Although the organic coolant concept has been demonstrated by the excellent operating record of the 40 MW WR-1 test reactor at the Whiteshell Nuclear Research Establishment, it has yet to be tested in a system which produces electric power. It is technologically one of the most promising of the CANDU variants. Nevertheless, a decision was taken this year to tidy up the loose ends and put the technology on the shelf rather than proceed with a prototype reactor. The reason for this decision was to avoid the risk of spreading out the Canadian effort too thinly at a time when the heavy-water cooled reactors were just establishing a commercial position. However, it is entirely conceivable that within the next 20 years interest in this concept will be revived, possibly coupled with the use of a thorium fuel cycle as suggested by Dr. Lewis.18,19 The reason that the thorium fuel cycle and the organic cooled concept go hand in hand is that the U233 which is bred from thorium does not suffer the same loss in reactivity as does U235 and plutonium with the increase of neutron temperature that results from a higher temperature coolant. THE FISSION BREEDING OPTIONS Thorium and U239 are both abundant fertile materials. They can be converted to fissile resources by the addition of a neutron to each, atom to produce U233 and plutonium respectively. 207

A figure of merit in any consideration of fertile to fissile breeding is "n" (the ratio of neutrons emitted to neutrons absorbed of the fissile atom produced). In theory, any reaction for which n = 2 can breed as much fuel as is consumed (i.e. would have a breeding ratio = 1). However, in any practical system, neutrons are lost by leakage and parasitic capture. A more realistic threshold for a breeding ratio of 1 is n = 2.2. The basic criteria for evaluating a system with regard to its breeding ratio are presented in Fig. 4. Note that the value of n is critically dependent on both the nature of the target atom and on the energy of the neutron responsible for f i r <; i o n . Clearly, efficient breeding is most favoured either by a system in which the fission neutron spectrum is reduced to very low energies by a good moderator or alternatively by one in which the energy of the neutrons is kept very high by the rigorous exclusion of moderating materials. These observations have led to the two major classifications of fission concepts; the "thermal reactors" in which a premium is placed on the efficiency with which the fission spectrum can be moderated to thermal velocities and the "fast reactors" in which the designer wishes to maintain the fission neutrons at fast velocities. It is also apparent from Figure 4 that the best breeding cycle for thermal reactors would be based on U233 from Th, while that for fast reactors would be based on Pu from U238. Fast reactor concepts have as long a history as that of thermal reactors. Clementine, a U.S. fast reactor experiment was commissioned in 1946 and EBR-1, a fast reactor, produced the first electric power (200 kWe) back in 1951. However, the development of a practical and viable system has proved to be a much tougher problem than was the case for thermal reactors. Attracted by the possibility of extending their fuel resources, the U.S., the USSR, the U.K., France, Germany and Japan all have major programs in the field. All of these countries will be accumulating large inventories of plutonium from their thermal reactors with which to start their commercial fast reactor programs. Many variants of the concept are possible.20 Fuel in both metallic and ceramic form has been considered. Gas, steam and a variety of liquid metals have been studied. Although there remain champions of alternative systems, there is now a surprising consensus that the earliest route to commercial fast reactors is the liquid sodium cooled, ceramic fuelled variant - the so called LMFBR for Liquid Metal cooled f_ast Breeder Reactor 208

NEUTRONS EMITTED NEUTRONS ABSORBED 3~ P(J239 • 233 EFFECTIVE BREEDING THRESHOLD

2 235 s*r

1 1000 FAST REACTOR SPECTRUM 100 „ FISSION RELATIVE «.-' SPECTRUM NEUTRON FLUX 10

THERMAL REACTOR SPECTRUM

10"2 10'' 10° 10 10z 103 IO+ 10s I06 107 NEUTRON ENERGY (

FIGURE 4 — The basis of breeding.

(Dr. C.H. Millar, private communication) 209

TABLE 4 TYPICAL CORE POWER DENSITIES FOR VARIOUS REACTOR TYPES Reactor Types Power Density Reference kWt/£ Thermal Reactors CANDU-PHW 11 .2 Gentilly 2 PWR 93 Burlington BUR 50 Brown's Ferry AGR 2.4 Dungeness B Magnox 0.9 Wylfa Fast Reactors U.S. ^580 Commercial Reactor Studies France 460 Phenix U.K. 366 PFR Soviet 480 BN-350 210

TABLE 5 21 RESOURCES UTILISATION BY THERMAL & FAST REACTORS

Running Net Consumptions g/ekW-yr Technology Fuel Cycle Reactor Type U Pu Th (or U233) Magnox 270 -0.54 - AGR 147 -0.17 Pu Export LWR 171 -0.29 - Late 1970s CANDU 110 -0.41

LWR 114 - Pu Recycle CANDU 60 1980s Fast Breeder FB 1 -0.23 - 1970s Th/U233 LWR 65 - 2 HWR 8 2 Late 1970s Th/U 23 HTGR 115 -0.20 5.5 211

At the moment, the only unit of prototype size which has been commissioned belongs to the Soviet Union (BN-350). The U.K. and French units are expected to come on line soon. The U.S. expects to spend $6 billion to bring their program to commercial fruition with a target date in the mid 1980s. The optimists are hopeful that the commercial date will be 1985. Pessimists claim the turn of the century and few would argue with 1995. Why this long? The LMFBR represents a convulsive change in technology from the thermal reactors. Liquid sodium at 500°C fs not the easiest material to handle and keep clean. In the interests of both fuel economy and capital cost the power density of the core is very much higher than that of thermal reactors (see Table 4). It is sobering to reflect that a right cylinder 1 metre deep by 2h metres in diameter is required to deliver 3000 MWt - enough to power Winnipeg! The preservation of good geometry in the core is a matter of both technical and economic concern. The fast neutron flux is 100 times higher than in thermal reactors. Every atom of material in the core is knocked out- of place once every few days. This coupled with high temperature.tends to make materials creep and swell. To achieve the required fuel economy, 8 to 10% of the fuel must be burned "up on each pass. Thj-s raises problems of geometric ste-bility which must be resolved, in tiie fuel design. j,' 1 _r ~ It is a challenging but worthwhile task. None can argue reasonably that we should not find the way to make best use of our plutonium, However, it is difficult to believe that the Fast Reactor will gain acceptance simply OP the grounds of resource extension. In Table 5 we see that the. CAN.DU reactor, with only evolutionary developments and requiring/only modest < expansion of^pur national effort, can greatly extend, existing resources v^and,tfHS without closing: any options Jor t:he fast reactor. ' .^ . ^ • . ';. •' ''"',_, . J ' In the isost sensible of all sensible worlds, we wijl; develop our heavy water reactors w Burn thorium and pur fast reactors to burn uranium, Either alone is si/ffi'c.i ent to /see; man through for-at leasf thousand!* of years. , i; C FUSION i

. Ever sin^e msh discovered'that the source ofs the sun"s energy <"esulted •from the, fusion of hydrogen, he has drecffit of using the limitless supplies of hydrogen in water to generate his other energy heeds. The'objective of fusion research .is, to identify the conditions under which, this can* be done and:^to-discover how to produce such conditions at will- v 0

I 212

In theory, many reactions can be considered. All require a very demanding set of criteria. However, there are but two likely candidates, they are -> He3 + n + 3 MeV f i \ n J. n v" ' "IU-T + H + 4 MeV (2) D + T - He" + n + 17.6 MeV The first of these is known to require conditions at least in orders of magnitude more difficult to achieve than the second. The only reaction receiving serious attention as a possible fusion power source is that of D upon T (deuterium upon tritium). Enough is now known to define the criteria of scientific feasibility which must be met in order that as much energy is produced as is consumed in the process. A typical set of conditions which would meet these criteria is the achievement of a concentration of tritium-deuterium plasma of about 10llf particles/cm3 at a temperature of 108 degrees K and a confinement time of one second. Alternatively, higher densities can reduce the time required for a sufficient reaction to take place. Two general approaches have been considered which I would like to review very briefly. The first of these is known as the magnetic confinement concept and has been the subject of intensive attention since the time of the Second Geneva Confer- ence in 1958. The basic idea is that charged particles interact with a magnetic field and since the plasma is a mass of highly charged particles, it should be possible to contain them in a magnetic bottle. The development of superconductors has opened the door to the very high magnetic field strengths needed. It is now credible that magnetic fields can be produced of sufficient intensity (^100 kilogauss) to effectively contain a plasma by applying a pressure of over 400 atmospheres.22 The essence of the problem has been how to design such a magnetic bott'ie to avoid leakage of plasma through inherent instabi1ities.23 The state of the art is probably best represented by the current conser-us of optimism developing around the Tokamak (_a device first conceived in the USSR). At the moment each of the criteria described earlier has been achieved independently. To meet them simultaneously is expected to require at least one more generation of plasma devices. To this end, the USAEC is considering the commitment of a large $100M device, targetted for completion around 1982.24 The European fusion community is also considering the construction of a large Tokanuk device.25 Assuming that the above experiments do indeed prove scientific feasibility, the application of the concept to power generation raises a number of formidable problems before a com- mercially viable source of fusion energy will be possible. 213

There have been some conceptual studies of what would be required to produce a power generating device of practical interest based on the Tokamak principle. These indicate that the reactor will need to be of rather large volume (about 1,000 cubic metres). In it, a magnetic field will have to be produced of 100 kiloqauss by a superconducting magnet. Such, a device would burn in the order of 1 kg of tritium per day which will have to be produced by the system itself. To close the fuel cycle, the tritium will have to be produced in a blanket of lithium bombarded by the high energy neutrons emitted from the plasma. The containment system will have to be designed to withstand intensive radiation damage while being cooled with the tritium breeding blanket of liquid lithium. Like sodium, liquid lithium is quite aggressive and one would have to be assured that it does not transport the materials of construction. Outside of all this will be the superconducting magnet operating near absolute zero. Production of the strong magnetic fields will pose some formidable problems associated with the circulation of conducting coolants and in the structure of the magnet itself. Perhaps enough has been said to support the view held by most proponents of fusion power that it is unlikely to achieve commercial status 'mtil the year 2000.

At the Seventh International Quantum Electronics Conference in Montreal in May 1972, an alternative to the magnetic confinement system was disclosed by the U.S.27 This, too, is based on the deuterium-tritium reaction. The essence of the scheme is that laser light is impinged on a small pellet containing deuterium and tritium with the deposition of sufficient energy to ablate the outer skin so quickly that an implosion of the pels^ts takes place to produce densities 10,000 times higher than normal. The fusion reaction ignites and burns from the inside out in about 10"11 seconds (about the time for light to travel 1/8"). The release of energy is therefore in the nature of a small hydrogen bomb explosion. A series of such explosions can produce a cyclic flow of energy. The idea excites interest because it gets around the need for the large expensive magnets associated with the magnetic containment technique. The implosion approach is receiving a great deal of attention . Just as last year might be designated the year of the Tokamak, this year might be called the year of the laser. There is as yet no feasibility demonstration for this approach. Several laboratories expect to attempt such a demonstration over the next 3 to 4 years. One should not minimize the problem of converting such a scheme to practical application. While large magnets are not required, one has still to cope with the problem of producing large, reliable high energy lasers, appropriate methods of delivering the energy uniformly, feeding the fuel and extracting the products of the explosion with high reliability and at low cost. 214

In summary, the state of the art is that scientific feasibility of a fusion device appropriate to power generation has yet to be demonstrated, but is receiving a great deal of attention. It is credible that the question of scientific feasibility will be resolved within the next ten years. If the answer is yes, the development of a practical power producing device must be considered at least as long a road as that of developing fission power plants. There is a popular misconception that fusion could give mankind all of the benefits of nuclear power with none of the legacies of radioactivity. Both routes which I have described will generate about 4 times as many neutrons per unit energy than does a fission reactor. It is inconceivable that such a flux will not generate a significant radioactive inventory. Indeed, it may well transpire that the first practical application of fusion will be as a neutron generator to feed a fission system.28

CONCLUSION The development of the CANDU family of reactors coupled with oiir large resources of uranium and thorium, assures Canada of economic and abundant electric power into the foreseeable future. For the rest of the world, the heavy water option is now a competitive source of power and a viable alternative for those who had previously been dependent on the prospects for fast breeders and fusion a? long-term energy sources. ACKNOWLEDGEMENTS I am indebted to Dr. C.R. Hoffmann, Dr. C.H. Millar and Mr. E. Critoph for the assembly of the material on which most of the presentation is based. 215 REFERENCES

1. LEWIS, W.B. Nuclear energy and the quality of life. IAEA Bull. Vol. 14, No. 4, pp 2-14, IAEA, Vienna 1972. 2. WEINBERG, A. & HAMMOND, R.P. Global effects of increased use of energy. Proc. 4th U.N. Conf. Peaceful Uses of Atomic Energy, Geneva, 1971. Vol. 1, p.171. Paper P.033. 3. World list of nuclear power plants. Nuclear News, Vol. 16, No. 11 , Sept. 1973, pp. 53-62. 4. DAVIS, W.K. et al. United States light water reactors. Proc. 4th U.N. Conf. Peaceful Uses of Atomic Energy, Geneva, 1971. Paper P.034. 5. VAUGHAN, R.D. & Anderson, E. The Bradweil power station. Proc. 2nd U.N. Conf. Peaceful Uses of Atomic Energy, Geneva, 1958. Vol. 3, p. 450, paper P-263. 6. MOORE, R.V. A Review of Experience with Gas Cooled Reactors. "Atom", No. 147, Jan. 1969, pp 6-22. 7. McCONNELL, L.G. Construction and operating experience with thermal power reactors in Canada. Amer. Nucl. Soc, Washington, Nov. 12-17, 1972. TGD-1. 8. Heavy-water power reactors. Proc. Symp. Vienna. Sept. 1967. IAEA, Vienna 1968. 9. EGGLESTON, W. Canada's Nuclear Story. Toronto, Clarke Irwin, 1965. 10. MOORADIAN, A.J., Canadian nuclear fuel - challenges met and pending. Twelfth AECL Symp. on Atomic Power. Atomic Energy of Canada Ltd., publication No. AECL-3067. 11. MOORADIAN, A.J., Economic fuel for CANDU. Trans. 6th World Power Conf. Melbourne 1962. Vol. 4, pp. 1378-1408. (AECL- 1647). 12. Ross-Ross, P.A. Fuel channel development for Canada's power reactors. Eng. J. (Montreal), 1970, Vol. 53, No. 10, p.13 (AECL-3126). 13. United Nations. World energy requirements and resources in the year 2000. Proc. 4th U.N. Conf. Peaceful Uses Atomic Energy, Geneva, 1971. Vol. 1, p. 303, paper P-420. 216

14. RIPPON, S.E. Plutonium - problems and possibilities. Nucl. Eng. Int. Vol. 17, pp 85-92. Feb. 1972. 15. LEWIS, W.B. How much of the rocks and the oceans for power? Exploiting the uranium-thorium fission cycle. Atomic Energy of Canada Limited, publication AECL-1916, 1964. 16. KEEN, N.J. et at. Extraction of uranium and other inorganic materials frrm sea water. Proc. Conf. Technology of the Sea, Harwell, 1967. UKAEA publication. AERE-R-5500, Vol. 2. p.387. 17. Joint Committee on Atomic Energy hearings, Aug. 1973. Reported in: Nucleonics Week, 6 August 1973, p.2. 18. LEWIS, W.B. et at. Large-scale nuclear energy from the thorium cycle. Proc. 4th L). N. f"onf. Peaceful Uses of Atomic Energy, Geneva 1971. Paper P-157. 19. LEWIS, W.B. The super-converter or valubreeder: a near-breeder uranium thorium nuclear fuel cycle. Atomic. Energy of Canada Limited, publication AECL-3081 , 1968. 20. Proceedings of the Conference on Safety, Fuels and Core Design in Large Fast Power Reactors. Oct. 11-14, 1965. Argonne National Laboratory, publication ANL-7120. 21. OECD-ENEA. Power Reactor Characteristics. 1st Report, Paris, 1966. pp. 44-45. 22. ROSE, D.J., Science Vn_, 797, May 1971. 23. POST, R.F., Physics Today 26^ 30, April 1973. 24. Nucleonics Week, 1_4, 1, 26 July 1973. 25. Nucleonics Week, J_4, 6, 9 August 1973. 26. USAEC Report WASH-1239, February 1973. 27. .<(JCKOLLS, J., WOOD, L., THIESSEN, A. & ZIMMERMANN, G. Nature 2J3£, 139, 1972

28. LJOSKY, L.M., Proceedings of the BNES Conference on Nuclear F-.ion Reactors, Culham", 1969, p. 41. 217

GEOTHERMAL ENERGY; AN UNDEVELOPED CANADIAN RESOURCE?

G_D. GARLAND

University of Toronto

INTRODUCTION

That the earth itself is a reservoir of thermal energy has been recogni2ed for centuries. The increase in temperature with depth, observed in mines and boreholes, is evidence of an internal heat source, from which heat is escaping to the earth's surface. Most of this heat is believed to be produced by radioactive elements in the outer part of the earth, but a portion may represent residual original heat. However, while the total rate of energy loss is very large: 3.2 x 10^ megawatts, much greater than the rate of energy expended in earthquakes, the density of the thermal flux is, except in unusual regions, very small. Through more than 99% of the earth's surface, the heat flux is of the order of 1 microcalorje per cnr sec, far too small to be of use to man. It is only in the remaining 1% of the area that unusual conditions combine to give a much higher flux. These areas of higher density of geothermal energy have been utilized for many years in Iceland and Italy, and in more recent times in New Zealand, the United States, and other countries. There has rot yet been a commercial development of geothermal sources in Canada, except, of course, for medicinal hot-water baths.

The purpose of this paper is to assess the possible importance of geothermal sources upon the Canadian energy situation. Even if geothermal energy is not utilized in this country for some years, the extension of developments in the western United States and Mexico will change the continental energy balance, with implications for this country. In order to show the natural conditions that are required to r.oduce a geothermal field, and the installations that are involved in harnessing it, brief descriptions of fields in Italy, New Zealand and Iceland will be given and che possibility of similar conditions existing in Canada will be discussed. A description will also be given of a newly-proposed process, which involves the artificial circulation of water into areas that are not natural geothermal fields.

EXAMPLES OF GEOTHERMAL AREAS

Larderello, Italy Natural steara wells were known in this area, south of Volterra, at least as early as the eighteenth century. In 1777 the wells were developed for their boric acid content, and borax was extracted. The first use of the thermal energy came in 1904, when a steam-driven generator producing 40 h.p. was installed. Today, about 160 wells are drilled into the field, to a maximum depth of 1600 m., and these produce steam at the rate of almost 3,000,000 kg. per hour (Burgassi 1964). A most important feature of the Larderello field is that the steam is dry, many wells producing superheated steam at temperatures of the order of 200°C. The steam is used to drive the turbines of generators, producing electric power at the rate of 380,000 kw. Fig. 1. Developed geothermal areas of the world (crosses) in relation to plate boundaries and hot spots (circles). 219

Geologically, the area is one generally associated with young volcanism, although volcanic rocks are not exposed in the immediate vicinity of Larderello. The field itself is located on a upfaulted block within a sedimentary basin. This basin contains a thick sequ nee of permeable anhy- drite overlain by an impermeable clay, and it is believed that this combination ia ul great importance in determining the nature ot the field.

Wairakei, New Zealand The Wairakei field is located within a zone of active volcanoes, which extends for 300 km. across North Island. (Healy, 1964). Development of the field began in 1950, and about 100 wells have now been drilled. Electric power is in production at the rate of about 150,000 kw., to be increased eventually to 250,000 kw.

Geologically, the field is located on a local upfaulted block within an area of subsidence. The aquifer is a pumice breccia, capped by a relatively impervious mudstone, which is itself overlain by young volcanic rocks. One deep well has passed through the aquifer into underlying young volcanic rock, which is believed to be related to the source of heat.

The most striking difference between the Larderello and Wairakei fields is that while the former produces superheated, dry steam, the Wairakei wells produce fluids of varying thermal quality, ranging from hot water to saturated steam. This property is believed to be related to the lateral extent of the porous reservoir rock, which, in the case of the Wairakei field, allows cold ground water to mix with the steam in various proportions.

Iceland Iceland is ar. island formed entirely of volcanic rock, lying on the axis of the mid-Atlantic Ridge. Hot water springs and natural outlets of steam have been known for many years, and have been utilized for domestic- heating for decades. Application of geothermal energy for power production began with the design of a 15,000 kw, generating station in the Hengill area near Reykjavik.

Heat sources in Iceland are divided into low temperature and high temperature types (Bodvarsson 1964). Low temperature sources are character- istically hot-water springs, producing water at a temperature of 100°C, and often arranged in linear patterns, suggestive of structural control alon^, faults. High temperature sources, which produce steam, are restricted Lo the neo-volcanic zone of most recent volcanic activity. There is evidence, from the isotopic content of the water, that it is of surface origin, rather than juvenile water released in the volcanic process. In this regard, the fields are similar to others, and a reservoir, capable of permitting fluid circulation, must be present. As sedimentary rocks are not present, the reservoir porosity must be provided by fractures in the volcanic rocks.

Bodvarsson has estimated the total potential of the Icelandic thermal areas at 300 megawatts. The present utilization of geothermal energy for heating is equivalent to 60,000 tons of coal per year.

Descriptions of other geothennal areas of the world may be found in Ruiz Elizondo (1964) and McNitt (1965). 220

QC i

FUMAROLE

\ VAPOUR INFLOW OF GROUND WATER

LEVEL OF VAPORIZATION I

WATEP CONVECTION CALLS

HOT ROCK

2. A vapour-dominated geothermal system (after White etal) 221

PHYSICS OF GEOTHERMAL AREAS

The above examples have shown some common features, which are typical of all geothermal areas: proximity to geologically young volcanism, transport of heat to the surface by hot water or steam produced from surface water, the presence of a porous aquifer to permit the circulation of the water and to provide the reservoir.

The global distribution of regions of young volcanism is now rather well understood in terms of plate tectonics (Fig.l). Most volcanic areas occur near the boundaries of the rigid plates, into which the outer part of the earth appears to be divided. Very often, these regions are also areas of high seismic activity. Plate motion is believed to be controlled by some system of convection in the mantle of the earth, the currents rising and spreading under oceanic ridges, and drawing the plates down under subduction zones. Recently, however, it has been proposed (Wilson and Burke 1972) that the convection system is complicated by the presence of plumes, which carry heat and material to the surface, and whose relation to a general convection system is not yet understood. Plumes may be recognized by the outpouring of unusual volumes of volcanic rock, as in the case of Iceland, a plume on a ridge, or Hawaii, the result of a plume beneath the interior of a single plate. Potential geothertnal areas are therefore to be expected either near plate boundaries, or in conjunction with plumes beneath the 4 it' ..iors of plates.

The surface expression of these areas varies greatly in intensity, from springs of moderately hot water, to outpourings of steam. White et al (1971) have discussed the mechanics of geothermal reservoirs with the aim of clarifying the distinction between vapour-dominated (i.e. steam) and fluid dominated fields. Figure 2 shows their model of a vapour-dominated system. Heat is carried upward from hot rock by a water convection system. Closer to the surface, the reduction in pressure permits water to boil. This depth forms the lower margin of the main body of the reservoir. In the main reservoir, steam and water coexist. Closer to the surface, steam condenses and heat is carried by both water and steam. Steam may escape to the surface along major channels. If the supply of surfa-.e or ground water is too great, the large vapour-dominated region of the reservoir may not develop. The difference in type of field is therefore determined by the effectiveness of the cap rock, and the extent of porosity in the reservoir. In fields such as Larderello, and also the Geysers, California, the inflow of water relative to the heat supply is controlled, so that steam predominates.

An alternative representation of a geothermal reservoir is by means of a "pipe model", in which the cross-sectional areas and velocities are indicated. Figure 3, adapted from Elder (1965) shows such a model for Wairakei. A notable feature is the range of times involved in the recharge and recirculation systems. While the figures shown represent estimates only, there is evidence from isotopic studies on the time required for water to circulate (Hulston 1964). Measurements on Wairakei water show that 92% of the water from the field is meteoric, and the tritium content of this water is so low that the time it has spent in the earth must be considerably lOkltij*"-1 2 days— >»% , C RECBCULATIOM / IOOO r / (^" 100 km2 \ / V

26.000 yr

420 cal/gm

RECHARGE

MOT ROCK

Fig. 3. Pipe model representation of circulation in a geothermal system (after Elder). 223

greater than one half-life of tritium (125 years). The total volume output of the Wairakei field would be provided by only 5% of the present annual rainfall in the catchment area of the field.

EXPLORATION AND PROVING

While the distribution of young volcanic rocks gives a broad guide to the regions in which to explore for geothermal fields, it is necessary to have methods to localize the search. Fortunately, a number of the methods of geophysical prospecting are immediately adaptable, since the reservoirs are nothing more than regions of anomalous physical properties. Measurements of the electrical conductivity of the crustal rocks, which can be made from the earth's surface, from a powerful exploration tool. The conductivity of rocks increases with temperature, so that the elevated temperature of a geothermal area can be detected directly. Early experiments were conducted in Iceland (Bodvarsson 1964), and electrical methods of exploration are now widely employed. In some regions,, there is a correlation between minor seismic activity and geothermal areas. The monitoring of seismic noise by networks of portable seismographs T. ill, in those cases, indicate the most promising locations. In the United States about $50 million per year are currently spent on the geophysical search for geothermal areas.

However, as in the search for oil and minerals, the location of a geothermal anomaly does not mean that a commercial resource is present. It is necessary to evaluate the total rate of output of hea* ,'om the area, and also to consider the thermal quality of the fluids (temi :.~iture of water, and energy content per unit mass, or enthalpy, of the steam). Within the bounds of a potential field, heat is discharged by conduction through the soil, by convection from water surfaces, in steam from steam vents (fumaroles), in hot water from springs, and by seepage to streams. Methods have been developed, particularly in New Zealand (Dawson 1964) for assessing the importance of each of these, using only shallow augur holes. The potential of a new area may be estimated before more expensive drilling is undertaken.

THE HABNESSING AND ECONOMICS OF GEOTHEKMAL POWER

Electrical production at the major fields is by means of steam- driven turbines. In the case of a dry-steam field such as Larderello, the design of suitable generators is relatively straightforward. The more common situation is that typified by Wairakei (Armstead 1964), where different wells in the field produce steam at different pressures and of different degrees of saturation, or simply hot water. In these cases, the generating plant must be carefully designed to optimize the utilization of the different fluids. At Wairakei, hot water is only used if, when its pressure is reduced to an intermediate level, it boils ("flashes") to produce steam. The plant (Fig. 4) has been designed to handle natural steam at two pressures, or the steam produced by flashing.

In considering the economics of geothermal power generation, a number of factors, not encountered in other systems, must be considered. 2 24

I P LINE L P LINE

HOT WATER FROM WELLS

CONDENSERS HIGH PRESSURE STEAM FROM WELLS

INTERMEDIATE

STEAM FROM WELLS

TURBINE REDUCING VALVE

Fig. 4. Utilization of fluids of differing thermal quality, in New Zealand (after Armstead) . 225

These include the estimated lifetimes of the field, and of individual wells, the deterioration of the fluid-handling system by dissolved substances, the cost of disposal of waste hot water, and the possible income to be derived by separation of valuable dissolved substances.

Geotfcermal fields, like all exploitable sources of resources, must have finite lifetimes, but because all known fields are still in production, there is very little evidence on the time,scale. There is evidence, from Maori legends (Healy 1962) that no gross changes in temperature have occured at Wairakei in one thousand years, and the geological evidence would support the existence of hydrotherinal activity there for the past million years. Much more serious is the finite lifetime of individual wells, since the drilling of new wells constitutes, a recurring charge' in the. exploitation cf a given field. Decrease in the, productivity of a *ell is believed to result from a decrease in the porosity, of the surrounding rocks, provoked by the deposition of dissolved substances in the pores. The experience at Larderello (Chierici 1964) has been that the flow of a well decreases as an inverse power of time; for the average well, the "production is reduced to 10% of the initial value in 20 years. Taking this rate of decrease, and estimating the cost of re-drilling, C'hierici gave the c.o'sts of geothermal power production in Italy as follows (30 megawatt geothermal plant; 300 megawatt fuelled plant; 1960 prices).

Geothermal Fuelled Electrical Installation per kw $130. - $150. $110. - $120. Operation per kwh. 0.12 - 0.13 C 0.06 - 0.07 C Fuel or steam " ' 0.08 - 0.09 c 0.50 - 0.55 e

While initial installation and operation costs are higher, the freedom from fuel costs makes the geothermal operation very attractive, in this case. Similar figures are available for the Geysers area in California, where the installation this year will reach 412 raw, (two-thirds of the requirements of San Francisco) and thereby surpass Larderello. Installation costs a-*-° quoted as $110/kw, and total operation, including steam, as 0.35

It will; be seen that the experience of those countries advanced in rlie use of geothennal power shows thai: installations in the range o£ 60 -220 megawatts are effective and efficient. The required production rate of steam or hot water to provide the energy for this is indeed impressive. For example, the experience at Larderello shows that 9 kg. of steam are utilized to produce 1 kwh of electrical energy. The required production rate for a 100 w, installation is thus 1 x 10" kg. per hour of steam equivalent to 24000 tons per day. For a field producing hot water (at 200°C) instead of steam, approximately three times as much water would be requireu, because of its lower enthalpy. 226

HOT ROCK Y ^

BOUNDARY OF CRACK

5. Proposed artificial recharge system. 227

The output mentioned for the Larderello plants corresponds to an overall efficiency of about 16%, in terms of the energy content of the steam. It is interesting to note that this is just about one half of the efficiency of an ideal engine operating between the input and exhaust temperatures of 250°C and 80°C respectively.

To date, the disposal of waste hot water has probably not been a major factor of expense, but with increasing consciousness of the problems of thermal pollution, it could well be a factor in the future. Obviously, large volumes of hot water, often heavily chargad with dissolved substances, cannot be discharged into fish-bearing streams. Geothermal plants are, of course, free of other forms of pollution.

A PROPOSED SYSTEM USING ARTIFICIAL RECHARGE

It is evident from the descriptions of natural geothermal areas that special, and fortuitous, combinations of circumstances are required: a source of heat near the earth's surface, and the correct combination of porosity and impervious cap rock to provide a reservoir. The utilization of geothermal energy would be much more widespread if the earth's heat could be extracted from other regions, where these conditions do not all exist. For example, there are numerous areas in western North America, where the outflow of heat is greater than the worldwide average, presumably because of recent igneous activity, but the reservoir conditions do not exist. A recent proposal (Robinson et al 1971) is based on the idea of producing an artificial reservoir system in such areas. Imagine a large-diameter (40 cm.) hole bored into a region of relatively hot rock, at a depth of perhaps 5 km, (Fig. 5). The average geothermal gradient is about 30°C per km., but in regions where the heat flow is twice normal, temperatures of the order of 300°C would be reached at this depth. Water at high pressure (1500 psi) is forced into this hole, to produce, according to preliminary experiments, a thin, circular crack lying in a vertical plane. A second large-diameter hole is drilled to reach the crack at a higher level, and water is circulated between the deep and shallower hole. Calculations show that heat could be extracted at the rate of approximately 90 megawatts for 20 years, before cooling of the rock rendered the source inefficient. However, during this time cooling of the rock could well produce subsidiary fractures, which would increase the area of contact between water and rock, actually rendering the system more efficient with time. Energy could be extracted at the rate of 90 megawatts by the circulation of 2 million gallons of water per day, assuming an input temperature of 50°C and an output temperature of 250°C. Once circulation is begun, it is expected to continue, requiring only the pressure resulting from the different densities of hot and cole columns. The hot water would return to the surface at a pressure above atmospheric and could be flashed to produce steam.

The possibility of achieving such an artificial recharge system depends principally on two critical factors: the development of economic systems for the drilling of deep, large-diameter holes, and the effectiveness of the pressure-induced cracking process. There is hope for the first, in 228

STEAM 68% GEOTHERMAL SYSTEM

ELECTRIC POWER in mt~

Fig.S. Use of natural steam to provide total energy requirements for a community (after Robinson et al). 229

the form of a nuclear-powered electric melting drill. While the second problem has been studied on the laboratory scale it appears impossible to be certain of the outcome in the real earth before deep holes are drilled, and the technique tried. Further theoretical studies (Harlow and Pracht 1972) support the validity of the assumptions, in particular the importance cf secondary thermal fracturing of the rock.

If the system is feasible, Robinson et al propose that the hot water be flashed, to produce steam for a generator of 10 megawatts (Fig. 6). The remaining water could be used for domestic heating, and possibly even to power vehicles driven by steam - turbine engines. (The flow of hot water shown in Fig. 6 for Transport is that required to power 10,000 vehicles for 30 miles per day). The complete installation, from the two wells, could provide the energy requirements for a community cf 10.000 people.

THE PROSPECTS IN CANADA

The experience from other countries shows that active geothermal areas are invariably associated with geologically recent volcanism. As we have noted, the latter activity is usually related to plate boundaries, or to intra-plate plumes. In Canada, young volcanism is characteristic of the western Cordillera, near the western limit of the Americas plate (Fig. 1). Isolated plumes have not yet been recognized in this country. Before turning to the Canadian possibilities in detail, let us note again that future geothermal developments along the western margin of the Americas plate, are almost certain to have an impact on the continental energy resource picture, and there an indirect effect on the Canadian situation.

In the Canadian Cordillera the volcanism has been discussed by Souther (1970). Of great significance to possible sources of geothermal energy is his recognition of belts of Quaternary (i.e. younger than approximately one million years) volcanoes (Fig. 7). Host of i;hese volcanoes are small cinder cones, whose active life was apparently short. The youth of some of them is remarkable. A flow and cone at Aiyansh, B.C. west of Hazetton, has been dated at 220 £ 130 years, while Mt. Edziza, southeast of Telegraph Creek, is known to have erupted at least three times in the past 1800 years. The structure in the vicinity of Mt. Edziza suggests that a situation favourable to a geothermal field may exist, with faults and fractures providing the porosity. According to Souther, the region is one which was first subject to compressive stresses, producing thrust faults. A change in the stress system led to a condition of tension, permitting the formation of a downfaulted block, on which the volcanic cone is situated.

Measurements of heat flow in the Canadian Cordillera are in progress, by the Earth Physics Branch, Department of Energy Mines and Resources. Jessop and Judge (1971) have reported the relatively high value of 1.86 x lO-Gcal/cm^sec fc anticton in southern British Columbia. The extension of heat flow meas aents into the neo-volcanic zones will be most important. Even if natural •thermal fields are not located, the outlining of regions of high heat flow .pproximately 2 x 10"6 cal/cm2sec or greater) will indicate the possible locations of Zuture artificial-recharge instal- 2 30

7. Location of Tertiary and younger volcanic rocks in

British Columbia (after Souther). The positions of Aiyansh (1) and Mi. Edziza (Z) are indicated. 231 lations, if that technique becomes a reality. More detailed geophysical investigations of other types, including electrical conductivity and micro earthquake studies also appear to be calle' for in the neo-volcanic belts. It is known that the western Cordillera is a general region of high electrical conductivity (Ganer, Auld, Dragert and Camfisld 1971), but the detailed mapping of the conductivity in the vicinity of the young volcanoes will require many more measurements.

The occurrence of hot springs is, of course, evidence of some source of geothermal energy. Harrison Hot Springs, and the springs near Terrace, both occur clos£ to the neo-volcanic belts, and would appear worthy of detailed study. In contrast, the hot springs of the Rocky Mountains (Warren 1927, Pickering 1954) hold little promise for geothermal energy production. The water temperature is low: on the average, about 115°F, and there is no nearby source of volcanic heat. The explanation given by Warren for the Banff springs appears correct, that surface water circulates to depth, along fractures, in a region of normal geothermal gradient. If this is the case, there is no possibility of obtaining steam, or water sufficiently hot to flash to steam.

Throughout most of the remainder of Canada, evidence of geothermal sources, and of high heat flow (Jessop 1968) is lacking, Geothermal possibilities appear limited to British Columbia and the Yukon. As has been shown, steam fields certainly can produce electrical power at competitive costs to other types of generation, and hot water fields, if of sufficient thermal quality,probably can. The method compares favourably, in its impact on the environment, with either large hydro-electric installations, and with plants using fossil fuels. Furthermore, the seismicity of the western Cordillera may well argue against hydro-electric dams in certain areas. The search for geothermal fields would therefore appear to be well worthwhile, although, until the development of the artificial recharge system, the necessity of proving substantial flows of thermal fluids, as discussed above must always be kept in mind. 232

References Armstead, H. Christopher H., 1964, Geothermal power development at Wairakei, New Zealand, U.N. Conference on New Sources of Energy, 3_> 274-282.

Bodvarsson, Gunnar, 1964, Physical characteristics of natural heat resources in Iceland. U.N. Conference on New Sources of Energy 2_, 82-89.

Bodvarsson, Gunnar and Johannes ZoBga, 1964, Production and distribution of natural heat for domestic and industrial heating in Iceland. U. N. Conference on New Sources of Energy 3_> 449-455.

Burgassi, Renato, 1964, Prospecting of geochermal fields and exploration necessary for their adequate exploration, performed in various regions of Italy. U.N. Conference on New Sources of Energy, 2_, 117-133.

Caner, B., D.R. Auld, H. Dragert and P.A. Camfield, 1971, Geomagnetic depth sounding and crustal structure in western Canada. Journ. Geophys. Res. 2i, 7181-7201.

Chierici, Averardo, 1964, Planning of a geothermal power plant; technical and econond.c principles. U.N. Conference on New Sources of Energy, 2, 299-311.

Dawson, G.B., 1964 The nature and assessment of heat flow from hydrothermal areas. N,Z. Journ. of Geol. and Geophys. I. 155-171.

Elder, John W. 1965, Physical processes in geothermal areas. In Terrestrial Heat Flow (William H.K. Lee, Editor). American Geophysical Union, Monograph 8.

Harlow, Francis H. and William E. Pracht, 1972, A theoretical study of geothermal energy extraction. Journ. Geophys. Res. 77- "038-7048.

Healy, J., 1962, Structure and volcanism in the Taupo volcanic zone, New Zealand. Amer. Geoph. Un. Monograph 6, ed. G.A. Macdonald and H. Kuno, 151-157.

Healy, J., 1964, Geology and geothermal energy in the Taupo volcanic zone, New Zealand. U.N. Conference on New Sources of Energy .2, 250-256.

Hulston, J.R., 1964, Isotope geology in the hydrothermal areas of New Zealand, U.N. Conference on New Sources of Energy, 2_, 259-262.

Jessop, A.M., 1968, Three measurements of heat flow in eastern Canada. Can. J. Earth Sciences 5_, 61-68.

Jessop, Alan M. and Alan S. Judge, 1971, Five measurements of heat flow in southern Canada. Can. J. Earth Sciences J5, 711-716.

McNitt, James R.f 1965, Review of geothermal resources. In Terrestrial Heat Flow (William H.K. Lee, Editor). American Geophysical Union, Monograph 8. 233

Pickering, B.J., 1954, Principal hot springs of the southern Rocky Mountains of Canada. Alberta Society of Petroleum Geologists, Guidebook, Fourth Annual Field Conference.

Robinson, E.S., J.C. Rowley, R.M. Potter, D.E. Armstrong, B.B. Mclnteer, R.L. Mills, M.CO Smith, 1971, A preliminary study of the nuclear subterrene, Los Alamos Scientific Laboratory, Report LA - 4547. Ruiz Elizondo, Je'sus, 1964, Prospection of geothermal fields and investigations necessary to evaluate their capacity. U.N. Conference on New Sources of Energy 2^ 3-23.

Souther, J.G., 1970, Volcanism and its relationship to recent crustal movements in the Canadian Cordillera. Can. J. Earth Sciences, I, CO C£ O

Warren, P.S., 1927, Banff Area, Alberta. Geol. Surv. Can. Memoir 133.

White, D.E., L.J.P. Muffler and A.H. Truesdell, 1971, Vapor-dominated hydrothermal systems compared with hot-water systems, Economic Geology, 66, 75-97.

Wilson, J.T. and Burke ,Kevin,1972, Two types of mountain building. Nature,232, 448-449. 235

ENERGY CONVERSION: FUEL CELLS AND ELECTROLYSIS

B. E. CONWAY, F. X.S.C .

Chemistry Department, University of Ottawa

and

A. K. VIJH

Hydro-Quebec Research Institute, Varennes

Fuel cells allow the possibility of direct conversion to electricity of the energy potentially available from the combustion of a fuel without involvement of mechanical systems with moving parts, e.g. turbines or dynamos. Essentially a fuel-cell is a type of battery in which the electrical energy generating materials are the fuel, on the one hand, and air or oxygen on the other and the electrochemical reactions in the "battery" are made to occur at two electrodes.

The first electrochemical energy conversion from fuel substances and air or oxygen was realized by Sir William Grove (1839) after the discovery of electrolysis (of water) itself by Nichol- son and Carlisle. Grove not only succeeded in establishing (184?) a "gas battery" with hydrogen and oxygen but recognized that other substances could be similarly used, e.g. chlorine and carbon monoxide. Later, Haber and Moser developed a fuel cell employing carbon monoxide and oxygen in a high temperature system consist- ing of two Pt film electrodes formed on each side of air-heated glass tubes acting as a solid (super-cooled fluid) electrolyte.

Various modifications of fuel cell systems were developed but were relatively ineffective until the work of Bacon commenced in 1932 and culminated in 1959 with a 5 kW hydr ogc-n/oxy RI-II power source which was the predecessor of the Pratt and Whitney systems for the Apollo series of spacecraft. The Bacon system employs relatively cheap electrode materials (nickel) and a strong potassium hydroxide electrolyte operating at elevated but not inconveniently high temperatures.

2. Advantages of Fuel Cell Systems

The principal advantages of fuel cell systems over conventional energy conversion processes are (a) the directness of the

A more technical version of this paper is available on request from the authors. 236

energy conversion operation: fuel and oxidant (air) are fed in on a continuous basis and electric power is immediately available without involvement of reciprocating or rotating (turbine) components (secondary pumping and heat exchange systems may require such auxiliary machinery). (b) In distinction to batteries which "run-down" due to consumption of the electrode materials from which they are made, a fuel cell will operate, in principle, continuously so long as fuel and air are supplied. (c) The conversion of the energy available from oxidation of the fuel can, in principle, be made with 100% efficiency in a fuel-cell while thermal conversion systems e.g. power stations generating electricity by combustion of coal or oil, have a theoretical maximum efficiency of 40 to 50Z, and practically of 30-35%.

3. Energy Conversion Efficiency

The question of efficiency must be discussed in more detail for it is one of the principal factors that make fuel-cell systems attractive in relation to thermal energy conversion processes.

Any combustion process, e.g. of coal, oil or hydrogen^is a chemical reaction in which there are rearrangements amongst the nuclei of the atoms of the molecules concerned and a redistribu- tion of the electrons between the reactant molecules. Associated with such chemical reactions is a certain maximum available amount of energy that can be obtained from a given fixed quantity of the substance, the fuel. This maximum available energy is called the free energy. When a combustion reaction (oxidation of the fuel substance by oxygen in air) occurs in a thermal energy conversion process, e.g. in a power station, this maximum or free energy of the combustion process is never obtained. This is because the heat generated by the combustion, which is available for raising steam, is usually less than the maximum available energy because some fraction of the latter is dissipated in other ways which cannot be avoided for fundamental theoretical reasons. The efficiency with which the heat evolved in a combustion reaction can be utilized is determined by the temperature at which this heat is generated in relation to the temperature of the surroundings. Thus, in thermal energy conversion only a part of the total available energy is available at a certain relatively low efficiency of 40-50%.

In a fuel-cell, however, the rearrangements of electrons in the combustion reaction referred to above can be controlled in a special way by allowing oxidation of the fuel substance, e.g. H2 to occur at a metal electrode surface by release of electrons into the metal, and corresponding reduction of the air or oxygen at a second metal electrode with consumption of the electrons released by the electrode process involving the fuel molecule.

By this mtuns, a voltage, as in a battery, is set up between the two metal electrodes and the electrons flow round a circuit thus directly generating an electric current,again as with a 237

Electrons Electrons

motor (work ptrformed) 1 ANODE C-ve POLE) -Voltege V^. CATHODE <+ve POLE) Sr

I Reaction Reaction

2H2-*4H*+(W O2 gas supply supply

Elecfrotyts Electrolyte t Separator

PRINCIPLE CF THE FUEL CELL USING HYDROGEN and OXYGEN

+ Net re@eti@n is 2H2-^ 4H +4e

with 02+4H*"+4«—^

that is 2H24-O2—-*- 2HgO, Q "combustion"

Fig.l Schematic representation oi a fuel ceil in which hydrogen and oxygen are combined ^Secfrochemi- Gtijly tci formi water. 238

battery. (See Figure 1) In this type of process, the reactions which go on at the electrodes are equivalent to a combustion process since we can write the fuel electrode reaction chemically, e.g, for hydrogen, as H -»• 2 H+ + 2e (in the metal of one electrode) (1) and the reaction involving air or oxygen at the other electrode as 2e (in the metal of the second electrode)+ 2 H + — 0 -*• K,0(2) The 2 electrons flow from one electrode to the other round the external circuit in which electrical power can be utilized. At the same time, hydrogen.j and oxygen are converted to water in the chemical reaction ^2 + "f °2 —*"H2° in tne ceH ant* this process is thus equivalent chemically and in the amount of energy it generates to combustion of hydrogen in oxygen.

In the fuel cell, however, this process, equivalent to combustion, can occur, in principle, with conversion of all the maximum available energy to useful electrical work or power. Its efficiency can therefore be 100%. The electrical energy generated from a fuel cell thus arises from all the maximum energy available in the combustion reaction and not just from the heat with some low efficiency.

In practice, however, some slowness of the reactions which occur at the electrodes arises and thus diminishes the voltage generated by the cell to values below the maximum theoretically expected value. This effect increases the greater is the current taken from the cell. It is called "polarization" of the cell and is an important practical factor which lowers actual operating efficiencies to values lower than the ideal figure of 100%. Much research h ^ been carried out to minimize these so-called polarization effects.

Similar electrochemical reactions equivalent to combustions can be carried out with other fuel substances such as piipane and methyl alcohol, but side reactions and other difficulties make the use of such fuels at present less desirable than hyd rogen.

4. Practical Aspects

The development of H2/O2 fuel-cell systems has reached a high degree of sophistication with correspondingly impressive levels of performance, 1000 A.ft"2 being a readily attainable current density. However, the cost per kW still renders such systems economically uncompetitive at present with more conventional energy conversion systems. High performance systems have been developed both along the lines of the Bacon type fuel-cell 239

(Pratt and Whitney) and with electrode structures for lower temperature operations ba^ed on Pt/Teflon matrices (American Cyan- amid Co.), for acid solutions.

Attempts at developing satisfactory fuel-cells which are able to run directly on carbon-containing fuels, e.g. hydrocarbons (especially propane), methanol, etc., have not been re- warded with success comparable with that attained with hydrogen/ oxygen cells. The use of a liquid fuel, such as methanol, is especially attractive but the electrochemical oxidation of this substance becomes inefficient after extended periods of time of operation of methanol-type fuel cells. For petroleum fuels, direct high temperature fuel-cells have been developed and operate, for example, on natural gas with a molten carbonate electrolyte. They offer attractive possibilities with regard to efficiency and high currents but the inconvenience of operating at 1GOG°C or more is a severe disadvantage and materials stability problems arise. Nevertheless, this type of system and the reformer type, have been seriously considered by Utility Com- panies for local electric generation purposes, e.g. in houses (see below).

These difficulties with carbonaceous type fuels have led to the development of hybrid fuel-cells in which the petroleum type fuel is made to undergo a so-called "catalytic reforming" reaction with water vapor to produce H2 which can then be electrc- chemically oxidized with high efficiency in a H2/02 fuel cell. In the hydrogen conversion ("reforming") reaction , other factors leading to inefficiency are involved, especially the fact that reforming is a reaction itself requiring energy. The hybrid fuel-cell with a catalytic reformer seems to be the favored system at the present time (see below). The requirement for automatic fuel metering and an elevated temperature for the reforming catalysts have led to complex systems engineering problems with corresponding escalation of price per• kW and inefficiency due to the power requirements of the auxiliary systems.

5. Fuel Cells; Current Status and Future Prospects Before examining the current position and future .possibilities of the use of fuel cells, it is pertinent to inquire into the factors that make these devices attractive, Ideally,:" a source of power having the following qualities is desirable:

- No atmospheric pollution; - No thermal pollution of rivers and lakes; - Noise-free operation; - No moving parts, so that high reliability ire performance is realized; y - High energy conversion efficiency for fossil or synthetic (e.g. H2) fuels; - No aesthetic damage as e.g., is caused by overhead t r ansmis s ion lines aiid-lar ge: generating afeajtions . 240

It is noteworthy that fuel cells fulfil all of the above requirements of an ideal power source. However, their widespread use is limited by their present level of technological development, especially with regard to costs of fabrication and catalyst materials (noble metals). In order to explore this point in more detail, it is useful to formulate some questions and pruvide pertinent answers, as follows: (1) Is reliable fuel cell technology available today? Can fuel cells of proven performance be purchased for a variety of day-to-day uses? Several companies have developed and tested reliable fuel cell systems. Recently, the most notable effort is that of the TARGET (Team to Advance Research for Gas Energy Transformation) programme undertaken by the Pratt and Whitney Company (U.S.A.) in cooperation with over thirty gas and electric utility companies. This programme was commenced in 1967 with a mandate to produce a commercial, economically competitive fuel-cell for terrestrial uses. Around May 1971, this programme employed nearly 1000 research and development personnel (1) and there are indications that the level of this effort has increased considerably with time. The group has developed experimental fuel cells of commercial potential, and the latest* version is the 12.5 kW power plant called "Powercel" PC11. Several modules of these cells have been successfully tested over a number of months in private homes, restaurants, stores, offices, apartment buildings and in utility sub-stations. A modular version containing six of these power plants (total 75 kW) is also being tested in the utility network by Hydro-Quebec. The results are distinctly encouraging although, as is inevitable in a newly engineered system, a number of deficiencies in the construction and design have been discovered including substantial decline of efficiency on trials. The answer to the first question formulated above is therefore that reliable but, expensive, fuel cell technology i_s_ indeed available. Also, it has recently been disclosed that these power plants are now ready to be produced on an assembly- line basis, although in limited quantities, so that in the near future it will be possible to purchase a fuel-cell unit as easily as a lead-acid battery (2) but with substantially greater expense per k watt.

(2) Are large-scale systems likely to be viable and available?

This point may be answered by referring to the fact that the Pratt and Whitney Co. is already offering to the electric, utilities a programme for developing huge power plants based on fuel cells. It is indicated that systems can be provided by 1977 for 26-MW power stations based on their so-called FCG-1

ft A more advanced "Powercel" (FC16) is currently in production. 241 fuel ceil. it is expected that the cost of the installed (1977) FCG-1 power plant will be $185. per kW with an overall efficiency of 38%; this is to be contrasted with the 1970 PC-11 system for which the cost of the installed fuel cell was $2000. per kW and the overall efficiency about 30%. It should be added that the present (1973-1974) cost of the installed power plant is around $40C. per kW with an efficiency of around 30% and a life expec- tancy of 2-3 years.

(3) Are fuel cells economically competitive today?

This question may best- be considered in relation to some economic estimates given in Table I.

Table I Cost and Projected Costs of Energy Generated by Pratt and Whitney PC-11 "Powercel" Units

Single Fuel-Cell Module Cost 1970 1975 1980 1970 1975 1980

£/kwh 59 17 14 18 8

These figures have been taken from an internal report (3) of Hydro-Quebec and are based on the data provided by Pratt and Whitney (PW) about two years ago. Although recent, more precise data on the "Powercel" PC-11 unit is not available (owing to proprietary considerations of PW), an approximate discussion of the current economic situation in terms of the data in Table I is not out of place here. It is clear that for ordinary terrestrial uses, the present cost of energy generated by present fuel-cell systems is prohibitively high and will remain so for several years. However, the situation regarding the application of these fuel-cells for ppecialized terrestrial uses is quite different. Some of these immediate, (i.e., in the time period e_a.- 1974-1979) economically competitive terrestrial uses of PW fuel cells are as follow?:

(i) Power for Isolated Communities

In isolated communities of low population density and at large distances from the transmission lines, fuel-cells become, 242

on a comparative basis, economically more attractive. This situation obtains in several communities in the north of Quebec (3, 4) and undoubtedly exists for isolated communities elsewhere. An economic study shows (3,4) that in comparison with the alternative (i.e. the present) mode of power generation for these communities, namely, by diesel-operated small power stations, installations using PC-11 should be competitive in about half the isolated communities in Quebec by 1975.

By 1980, it is estimated that the PC-11 fuel-cell plants can economically provide power to all the non-connected networks in Quebec, except perhaps on the Magdalen Islands. Although some of these economic predictions are perhaps open to modification or debate, it is indicated (3,4) that in the near future (i.e. the 1974-79 period), it would be more profitable to provide electricity to some of the non-connected communities by fuel- cells rather than by diesel-engined generators. In fact, it has been estimated (3,4) that Hydro-Quebec can save upto $1 million/ year (after 1980) if it chooses PC-11 power plants over diesels for the new installations (as well as replacements) in the isolated communities of Quebec which are too distant to be connected to main transmission lines.

(ii) Power for Military and Naval Purposes

High reliability and noise-free performance of fuel cells makes them attractive for a number of present day specialized applications of a military and naval (submarine) nature.

(iii) Other Applications

For a variety of other terrestrial applications, fuel-cells, even with their high cost, can easily become economically competitive. These applications are mainly concerned with the use of fuel-cells as mobile or easily manipulated discrete power units in much the same way as some quite expensive high energy- density (e.g., silver-zinc) batteries are used. Some of these possible applications of fuel cells are determined by their long term reliability (several months to years) as power packs for isolated island cottages, hunting lodges, or for emergency/stand- by uses in hospitals, aircraft systems, buoys and boats, etc.

(4) Will fuel-cells be an economically-competitive, important source of terrestrial power generation before the year 2000?

Here we may attempt to explore the future (i.e., the next two decades or so) role, as opposed to the immediate (i.e., over the years 1974-79) potential of fuel-cells in the context of the energy conversion picture as a whole. More precisely, it is important to know the possibility of wide-spread commercial use 243 of fual cells within the next couple of decades. This question is best examined in relation to the following topics:

(i) Cost Reduction by High Volume Production

The cost predictions in Table I, even for 1980, are based on a limited market for fuel-cells. If fuel-cells were to become adopted extensively (for reasons to be given below) as power sources, either by individuals or by electric utilities building several mega-watt power stations based on large numbers of fuel cell modules, within the next decade or so, high volume automated production techniques will be needed as in the present lead-acid and nickel-cadmium battery industry. Such techniques will inevitably lead to cost reduction in the production of fuel cells and hence to a more competitive position. Since, however, conventional means of power generation are already highly automated in other ways, it is not reasonable to expect dramatic new savings in the future.

(ii) Cost Reduction by Improved Technology

The significant (modern) research and development effort in the field of fuel-cells is less than twenty years old. In comparison with other technologies of comparable complexity and impact, this is not a very long period. In this sense, the field cannot be yet considered fully developed so that it can be predicted that significant new advances will be made in im- proving the activity and the stability of the fuel-cell catalysts within the next couple of decades. These advances, hopefully, will decrease the power losses and increase the active li e of fuel-cells, thus making them economically much more attractive.

(iii) Relation to the Hydrogen Economy (see section 6 below)

It has been pointed out (5) that the ultimate and universal fuel of the future will be hydrogen and that Society will shift from the use of fossil fuels to use of hydrogen. The primary source of energy in the next 100 years or so will be nuclear energy and it has been supposed, in some projections, that for a variety of reasons including environmental ones, these nuclear plants will be situated away from the centres of high population density and perhaps on floating platforms on the sea (5), or, in isolated coastal regions. It is estimated (5) that the most economic way to transmit this "electricity" to the population centres would be by means of hydrogen, produced by the electrolysis of sea water. The most efficient and advanced technique for the conversion of this hydrogen to electricity is, of course, 244

the hydrogen-oxygen fuel cell such as the PC-11. It is clear, therefore, that with the advent of the "hydrogen economy", the market for fuel cells will receive a new impetus, thus leading to their improved economic position because of high volume production and improvement of the fuel-cell technology resulting from new demand for the device. It is also important to mention here that the era of the "hydrogen economy" would inevitably lead to the investment of funds in the improvement of the technology of the electrolysis process• Since the process of electrolysis of water is essentially the opposite of the processes taking place in fuel cells, the two technologies and the principles involved in them are very similar. Hence, the era of the "hytirogen economy" would lead not only to direct increase of investments in fuel-cell technology but indirect improvements will also result because of the increased research and development efforts on the electrolysis process itself.

(iv) Environmental Considerations From the point of view of maintaining a clean-air environment, fuel cells, of course, are the ideal devices. With the mounting social and economic pressures against the alternative (generally, highly polluting) conventional forms of thermal power generation, fuel cells are bound to attain an economically and socially more attractive position in the future.

From the foregoing considerations, it appears certain that within the next two decades or so, the relative economic position of fuel-cells is bound to improve substantially because of combination of a variety of favourable factors. (6) The Hydrogen Economy and the Energy Conversion Question In recent years, it has been pointed out (5) that the increasing rate of utilization of fossil fuels, including the re- emergence of coal, will lead to significant atmospheric pollution by C

Hydrogen would be produced electrolytically from either, atomic reactor electrical power or with improved photo-voltaic or photo-galvanic devices (see below). The costs of transporting . .... H2 over long distances become comparable and then competitive (6) with the costs of transmission line systems for electricity beyond about 500 km according to recent analyses (5,6). The systems proposed are local fuel-cells for utilization of the 245

transported H2 or direct thermal conversion systems (less efficient). The transported electrolytic H2 is also envisaged as being directly employed in the metal ore reduction and chemical process industries.

Transduction of the potentially available free energy of combustion of H2 in local fuel-cell units is envisaged on a domestic level basis with the advantage of production of only very pure water as the product (no pollution by C02 or products of incomplete combustion of fossil fusls). Utilities are currently investigating the economic and other aspects of the feasibility of domestic fuel-cell systems and a full-page color advertisement by a public utility corporation in the U.S. appeared some three years ago in Life Magazine illustrating the "fuel-cell powered home."

While the present trials and applications of fuel cells are strictly limited, this present situation must be viewed in the light of attitudes to other historically significant advances in technology, e.g. to the early locomotive, automobile or to the earliest atmospheric (vacuum) steam engines developed by New- comen and later by Watt and, more recently, t" the gas turbine in its early stages of development. In the further development of such systems, necessity and technological skills overcame difficulties associated with efficiency and expense to produce energy conversion systems ultimately viable from an economic and engineering standpoint.

In the case of fuel-cell energy conversion systems, we are on the threshold of impressive developments as evidenced by the extent and success of recent work at Pratt and Whitney. There is still a long way to go, however, to make fuel-cell systems competitive in cost and scale with other energy conversion systems. Much more basic electrochemical research is required to examine mechanistic aspects of electrocatalysis, especially with respect to reactivity of "intermediate" fuels such as methanol, the most attractive of solution-soluble liquid fuels. At present, in this country, chere are probably not more than ten actual workers (not groups!) conducting research in this area, an almost ludicrously low level of activity. A much enlarged activity and level of financial support is immediately required in research institutions, industry and universities if we are to make competitive advances in this challenging field.

7. Conversion of Solar Energy; the Ultimate Energy Source

(i) Energy farm concept The ultimate source of energy for human activities upon the Earth is the Sun. Indirectly, of course, the Sun has in the past provided all the fossil energy resources through the photosyn- thetic cycle, a process which still continues and can be utilized 246

at present in the "energy farm" concept by cultivation of fast growing combustible vegetation.

(ii) Photo-voltaic and photo-galvanic systems

For direct conversion of solar energy to, e.g. electricity, interest is currently centered on photo-voltaic systems based on silicon single-crystal cells. Until recently, 0.6 x 10^ $ per k watt has been the quoted price for such devices as employed on Skylab. Obviously, this is unrealistic for practical utilization of such devices but a recent breakthrough indicates that the above price may be substantially diminished by orders of magnitude in the relatively near future.

Photo-galvanic cells, based on photo-electrochemical effects, require very much more investigation. Photo-galvanic effects have been known since the time of Becquerel but their utilization for energy conversion processes has been little investigated. Again, substantial Government support for research in this area is needed for investigation of systems that could be orders of magnitude cheaper per k waU than present silicon semi-conductor devices.

In considering solar energy conversion, it must be recalled than an area of 5 miles square receives sufficient incident solar radiation in sunny climates to provide power for a large city. If direct photo-voltaic or photo-galvanic systems could be developed, they would be pollutionless and impressively less damaging to the landscape and surroundings than present oil refineries and associated rail transportation and tanking facilities or pipelines.

Acknowledgments

We are indebted to Dr. P. Stonehart (Pratt and Whitney Air- craft) for provision of information on recent developments in fuel-cell technology at PW and to Professor J. O'M. Bockris for sending us recently published and some, as yet, unpublished material on the "Hydrogen Economy" and related topics.

References

(1) Walx Street Journal, May 19, 1971.

(2) P. Stonehart (of Pratt and Whitney Research Laboratories, Hartford, Conn., U.S.A.), private communication.

(3) J.G. Charuk and P.J. Gaudette, "Competitive Possibilities of Fuel Cells at Hydro-Quebec", Hydro-Quebec Internal Report No. 606-000/144, March .1971. 247

(4) J. Benoit in "FORCES", No. 20 (1972), pp.3 (available from Hydro-Quebec, 75 Blvd. Dorchester West, Montreal 128).

(5) J.O'M. Bockris, Science, 176, 1323 (1972); idem "Electro chemistry of Cleaner Environments", Plenum Press (1972); D.P. Gregory, Scientific American, 228, 13 (1973).

(6) J.O'M. Bockris, Electrochemical Science as the Basis to a Non-polluting Future Technology, (in press, 1973/4). 249

ELECTRICAL ENERGY TRANSMISSION

by LIONEL BOULET Director, Institute of Research of Hydro-Quebec

Nous ailons discuter dans cette conference le transport de 1'energie electrique. Nous considererons les differentes methodes utilisees pour les lignes ae>iennes et les cables et essaierons de deduire les possibility de chacune en analysant les problemes associ£s. Nous etudierons en premier lieu les lignes de transport ae>iennes.

A. LIGNES AERIENNES Transmission of large blocks of energy on long distances is achieved most reliably and most economically by means of overhead transmission lines. For about a quarter of a century, the use of bundled conductors with 2, 3 or 4 sub-conductors has become solidly established for EHV transmission lines. The highest voltage level for a line operating in a network is presently 765 kV. However, focus is now on the evaluation of performance and the assessment of problems likely to be encountered in the extrapolation of existing EHV levels into the UHV range. Overhead transmission systems up to 1500 kV and even 2000 kV seem technically feasible and economics will be a deciding factor for its adoption. In a long term view, environmental constraints will force plants out farther from load centers leading to the problem of transmission of even larger blocks of energy than is now encountered. Interconnection of major high voltage networks is also seen as a likely application of UHV.

Les lignes de transport aeriennes a tres haute tension permet- tent de transporter une grande quantite

1. Isolation e^terne dans l!air. 2. Effet cosjronne sur les conducteurs. 3. Influence de la pollution et de la pluie sur le comportement des isolateurs haute tension. 250

4. Isolation interne des equipements a tres haute tension.

5. Problemes mecaniques. Une breve description des travaux de recherche dans chacun des domaines est donnee ci-dessous. 1. Isolation externe dans 1'air. Les distances d'isolation dans 1'air des lignes de transmission a tres haute tension dependent surtout de la tenue des dites lignes devant les surtensions de manoeuvre. Afin d'obtenir les informations necessaires pour la conception des lignes jusqu'a 1500 kV ca, des etudes des distances d'isolation necessaires sont effectuees sur un modele a grandeur reelie de la fenetre d'un pylSne, pour des Scartements diffeYents allant jusqu'a 8.75 m. Les distances d'isolation dans 1'air constituent le facteur predominant du coQt des lignes de transport d'Snergie et des postes de transformation. Actuellement deux problemes sont impliques, 1'un concernant la distance phase-terre et 1'autre la distance entre les phases. Des etudes systSmatiques sont effectuees afin de determiner les distances necessaires en fonction de la tension du reseau. Ces etudes sont non seulement realisees pour chercher les distances d'isolation, mais aussi pour etudier le mecanis- me du claquage dans le cas de grands ecartements. Une connaissance detail lee de 1'amplitude et de la forme d'onde des surtensions de manoeuvre qui se produisent dans le rfiseau est n§cessaire pour le calcul des espaces d'isolation dans 1'air. 2. Effet couronne sur les condur..eurs. L'effet couronne est l'un des facteurs les plus importants dans le choix des dimensions des conducteurs pour une ligne de transport d'energie a haute tension. L'effet couronne produit sur une ligne S haute tension cause les principaux phenomenes suivants:

- Pertes d'eYiergie - Perturbations electromagnetiques - Bruits audibles Les pertes par effet couronne ont une influence lggere sur le choix gconomique des conducteurs. Les deux autres phenomenes ont une influence importante sur 1'environnement pr§s de la ligne. Pour les lignes de transmission a tres haute tension, les perturbations electromagnetiques (dans la gamme des'frequences de radio et de television) et les bruits audibles sont les facteurs qui decident du choix final des conducteurs. L'ensemble des nasses et de la ligne experimentale constitue un moyen tres efficace d'§valuer les caracteristiques de nombreux types de 251

conducteurs soumis a 1'effet couronne. Par exemple, u.ie sgrie d'essais a de"j§ ete compietge sur un grand nombre de faisceaux. de conducteurs dans les nasses, pour faciliter le choix preliminaire des conducteurs requis pour les lignes de 1100 kV considerees dans le projet de la Baie James. Le faisceau de conducteurs choisi sera soumis aux essais a long terme sur la ligne experimentale.

3. Influence de la pollution et de la pluie sur le comportement des isoiateurs haute tension. Le choix du nombre des isolateurs requis pour une ligne de transmission depend surtout du comportement des chaTnes d'isolateurs sous les conditions de contamination et de pluie. Z.J Influence de la contamination. Les etudes necessaires dans 1'etablissement d'une ligne s'ins- crivent dans une suite logique de realisations tendant a obtenir une meilleure isolation des lignes de transmission. La premiere etape consiste a determiner le niveau de contamination rencontre sur un site particulier. L1 application de diffe"- rentes methodes de mesure (enregistrement du courant de fuite, mesure du dep6t de pollution sur les isolateurs, determination en laboratoire de la tension de contournement d'isolateurs pollu§s naturellement, etc.) doit faire 1'objet d'une premiere etude. L'etape suivante est Vame1ioration de Visolation des lignes eiectriques dans des zones contaminees. L'IREQ conduit actueile- ments en laboratoire et sous conditions natureiies, des essais tendant a determiner 1'efficacite des nombreux moyens existant, c'est-a-dire: recouvrements hydrophobioues (graisse, silicone), glagure semi-conductrice, forme d'isolateur modifiee, isolateurs en matigre synthetique (teflon, etc.). Le type d'essais effectu§s en laboratoire peut se faire sous un brouiliard propre ou sal in, seion une procedure normalised par la CEI, ou une procedure spgciale selon les buts vises.

3.2 Comportement des isolateurs sous la pluie. Des normes, datant de plusieurs dgcennies, d§crivent les conditions d'essais sous la pluie des isolateurs, pour les accrgditer. Con.sidgrant les futurs essais sous pluie des equipements a tr§s haute tension, il y a des difficulty pratiques pour obtenir les Tongues distances d'arrosage et simultanSment le taux de pr§cipita- tion spgcifie par les normes standards. Ceci nous a amenSs a dsvelopper un nouvel Squipement d'essai qui puisse produire des jets d'eau pulsatifs. II etait de surcroTt necessaire d'approfondir nos connaissances du mgcanisme de claquage sous pluie et nos efforts 252

convergent dans ce sens. 4. Isolation interne des equipements a tres haute tension. Par isolation interne, on comprend 1'isolation des appareils de grande puissance qui ne sont pas exposes aux conditions atmospheYiques. Comme exemples importants, citons entre autres, 1'isolation des enroule- ments des transformateurs et des cSbleb sous-terrains. Ce type d'isolation comprend une grande variete d'huiles, de papiers imprggnes d'huile, de re- sines synthetiques et de matieres plastiques ainsi que des gaz comprimgs et le vide. Dans le cas des transformateurs a haute tension, le systeme d'isolation papier-huile est predominant. Dans ce domaine de recherche, nous devons concentrer nos activites sur le comportement. diglectrique de 1'huile et du papier huile sous haute tension et tres haute tension, surtout pour les transformateurs de puissance. 5. Mechanical Problems. The adoption of bundled conductors introduced also some mechanical disadvantages with respect to the equivalent single conductor. Line fittings are more complicated, ice loading is relatively higher, and the dynamic behaviour of the bundle introduced another source of concern for the utilities: sub-conductor oscillations due to aerodynamic wake inter- action. The numerous studies and experiments being carried out around the world on the vibration of bundled conductors is a good indication of the preoccupation of the transmission line engineers for that problem. The possible use of bundles of 6 and 8 conductors for UHV transmission lines accentuates even more the necessity for more efforts in that field. 5.1 Bundled Conductor Dynamics. Several types of oscillations have already been identified on bundled conductors. The majority of the vibration phenomena encountered in overhead lines can be classified in one of the following three types: - conductor galloping (0.1-1 Hz) - aeolian vibration (10-100 Hz) - subspan oscillation (1-3 HZ) A lot of knowledge has been gained through the years on those vibration phenomena. Galloping usually occurs with winds in the range of 5.0 m/s to 25;

15 m/s and the first four natural modes of the span can be excited. The large motions of galloping can bring the phase conductors sufficiently close to each other to produce arcing between them and power interruptions. The lack of adequate means of controlling those vibrations imposes economic burdens as utilities have to provide vertical and horizontal clearances well beyond what is necessary for electrical purposes. Galloping is in most cases associated with ice formation on conductors. Wind on non-symmetrical cross sections causes an aerodynamic lift component acting in the direction of motion. Bundled conductors appear to be more prone to galloping than single line. The severity of that type of oscillation is really closely related to weather conditions favoring passage of the temperature below and above 0° C in a high humidity area causing thin ice coat formation on the subconductors. Adequate methods of control such as prevention of icing, use of damping

5.2 Conductor I any - Static Loading A goncl understanding cf ice formation has b^er, gained in recent years. Cloud icing is now reckoned cts being the cause of the most important ice formation on conductors. It happens when a low cloud layer containing supercooled droplets is moving through ?. line. The droplets collide with the conductor? and freeze up. Depending on the wind velocity, the droplets size and the temperature, water droplets may have time to freeze completely before each impingement; it produces soft rime which has low density around 0.6 g/cnr5. When the rate of impingement is relatively high, water does not have time to freeze up completely resulting in a wet growth and a high density ice formation, 0.9 g/cm^, named glaze. Hard rime lies between those two cases and happens at the limit wher. water has just the time tc froeze up before the impingement of the fc'lowing drop- let. The ice is collected on the windward face of the object. As the actual diameter of the object that the wind sees increases with time, the ability of the object to attract the droplets continuously diminishes and results in a decreasing collection efficiency. The rate of ice formation on large diameters is thus smaller than for a small diameter object. In areas where icing conditions are serious, the smaller the number of subconductors the less the icing load will be. Thi', factor can influence the decision on the choice of number of subconductors fer UHV transmission line. Despite this knowledge, it remains still difficult to evaluate precisely the actual ico loading likely to occur on a line because of the lack of information on the meteorological conditions where the lines are built.

8. UNDERGROUND POWER TRANSMISSION There are several major reasons why in the future an increasing amount of electrical energy will be transmitted via high power capacity cables. The rapid growth of urban population density, the doubling of power consusr~-tion with every decade, the rising land costs and the esthetic objec- tions to overhead transmission lines point clearly to an ever increasing importance of underground power transmission cables in the future power systems which are to supply urban areas. In most lsr^s .ities, not only is the price of land for the right of way of an overhead ..rdnsmission line expensive, but often due to urban congestion, it is simply not available. f'Jost present overhead transmission lines within urban areas owe their existence firstly to economical considerations and, secondly, to technical com-iderations. For example, if one considers a transmission voltage of 340 «V, taen the underground lines may cost as much as 16 times that of the overhead lines of equivalent voltage rating. Furthermore, the typical 255

oil-paper insulated 345 kV cable would consume its own MVA ratinq in 42 km. If attempts were made to compensate the capacitative charging current of the cable so as to increase its useful power transmission length, the overall underground cable system cost would then be still further increased. Thus for the usual oil-paper cables operating at transmission voltages between 230 and 345 kV, the maximum underground runs do not on the average exceed 32 km. Evidently, due to this length limitation alone, underground power transmission must necessarily be confined to urban areas having large population densities. Omitting the underground cable cost considerations for the sake of argument, one could say that long distance underground transmission would be possible with the low capacitance dielectric systems of the type contemplated or used in compressed gas cables (C6C) or cryogenic cables. The development or perfection of such cables is however at least a decade away.

As rising urban population densities demand increasingly larger blocks of underground transmitted power, the present insulating systems of H.V. power cables are becoming subjected to increasingly greater performance requirements. In the not too distant past, any rise in the demand of electrical energy could be easily met by raising the transmission voltage and adjusting accordingly the insulation wall thickness of conventionally insulated oil-imprsgnated-paper cables. However, this universally accepted solution to the problem is now rapidly approaching a practical limit imposed by the magnitude of the dielectric losses inherent with oil-kraft paper systems. This is well demonstrated in case of the largest underground system voltage in use today, namely, the 3f5 kV cable network in New York City» where the dielectric losses are of the order of 27 watts per circuit meter. The installed pipe-type cab'es have a total length of 13 km, are forced cooled and have a rating of aLout 480 MVA. It is now a conceded fact that even with adequate forced cooling techniques, the use of oil - impregnated-paper cables much beyond 500 kV is not economically attractive. Furthermore, even below 500 kV in cases where the expensive charging current compensating equipment is not used, the required power ratings necessarily limit the lengths of the oil-paper cables down to a few thousand feet.

With conventional oil-impregnated-paper cables rated at 500 kV operation under forced-cooled conditions, an MVA rating of 600 is readily achievable. A recent study, with more encouraging results indicates the possibility of MVA ratings as high as 2000. For voltages in excess of 500 kV, the dielectric losses may be maintained within an acceptable level by substituting the oil impregnated paper system with other synthetic polyifier and liquid insulating materials having low dielectric loss characteristics. At 500 kV, a synthetic solid-liquid insulation is expected to provide a load capacity of around 800 MVA, which could be increased to about 1100 MVA at 750 kV. Under optimum forced cooling conditions, the latter value could be possibly extended to 3000 MVA. 256

It is evident from the foregoing discussion that to meet the immediate increase in power requirements of large cities, it is most expe- dient to refrigerate or force-cool the oil-impregnated-paper cables already in service with the presently lower load capacity. Cables which are installed in trays or pipe-tunnels may be air cooled by means of air-fans, while the buried cables can be cooled by circulating cold water within pipes installed adjacent to the cables themselves. The power transmission capability uf an underground electric cable is limited by the maximum cable operating temperature. This temperature is the direct result of heat generated in the cable and the surroundings' capability in the dissipation of this heat. Irrespective of the method of cable installation, the surrounding soil has conventionally been relied upon for the conduction and dissipation of the heat energy. The soil's low thermal conductivity, however, and its variation with locale, weather conditions and moisture content of the soil generally impose severe limitations and necessitate a wide safety margin on the current rating of cables. Improvements in current rating have been achieved by the use of special back-fill materials having good thermal conductivity and moisture retentiveness. With these improvements, the soil's heat dissipation capability has reached its practical limit while demands persist for greater cable ratings. Present developments reveal a trend towards forced cooling which can more than double the power transmission capability of underground cables. The circulation of water or oil either through pipes buried next to the cables or through a large diameter pipe containing the cables are some of the methods employed.. The fluid is cooled with air cooled heat exchangers uniformly spaced along the transmission line, or even refrigeration units. The major objection to such cooling processes is the substantial flow of fluid required to extract a useful quantity of heat and the extensive equipment and power machinery necessary to circulate and cool this flo».;. Other more novel ideas proposed for cable cooling include cooling by (evaporation, two-phase flow and evaporation-condensation principles. The principle of operation of the evaporative cooling system is based on the evaporation of water in the vicinity of the cables and the removal of the vapor either by a forced air flow, by natural flow, or by a suction pump thus effect.ng the dissipation of the generated heat. The change of phase in evaporation requires absorption of heat energy without a temperature change. When this occurs, much smaller temperature changes of the convecting fluid result than if no evaporation occurred. This im- plies '.hat fcr a given heat source strength, surface and fluid temperatures can be kept lower when evaporation is employed. All new cable installations should, however, in anticipation of the increasing load needs,be rated at higher voltages (345 or 500 kV) and special care should be taken to ensure a high thermal conductivity environ- 25/

merit to provide an effective heat sink under force-cooled conditions. The development of a reliable synthetic paper rablp for 750 kV operation ir still at least some three years away; preliminary results obtained with polyolifin papers in conjunction with polybutene impregnants have shown encouraging results. It should be mentioned that over the past few years, a considerable amount of effort has been put into extending the operating voltage levels of extruded cross-linked polyethylene cables. These cables have practically replaced oil-paper cables for distribution voltages up to 35 kV and have made significant in-roads into the 69 and 138 kV area. However, their extension into the 230 kV range and above appears at this time rather limited due to degradation and failure effects from corona dis- charges and treeing. Nevertheless, their extended use into the Eh'V domain would be most desirable because of their inherently lower dielectric losses and capacitance per unit length. The dissipation factor for polyethylene is of the order of 2 x 10~4 and the dielectric constant has a value of 2.2, a most significant improvement over oil-paper.

To meet the long term demand of increased power for large cities, one has to resort to rather unconventional cable designs. When power block transfers greater than 3000 MVA are involved, even the EHV synthetic laminar cable insulation system becomes quite inadequate. At this point, we essentially have a choice between gas pressurized and cryogenic cables. The gas pressurized cable design uses compressed SFc as insulation, with the conductor centered by means of epoxy spacers within a metallic pressure-tight tube. The cable, due to its gaseous dielectric, has extremely low dielectric losses and low capacitance per unit length. It would thus be suitable fo.* long distance underground power transmission were it not for the installation problems, which arise due to the fact that the overall cable has to be constructed from short pieces of pipe. Contamination of the spacer sjrfaces during the installation process may seriously lower the breakdown strength of the cable. Most present installations of this type of cable involve short lengths (usually <1000 ft) at transmission voltages of 230 kV. In fact, the present compressed gas cables are mainly used for interconnection with SFg gas insulated substations and, in this respect, they may be regarded as an extension of the bus-bar. Capacities of 800 MVA at 230 kV systems are common; lately, studies have indicated that the ultimate power capacities of CGC systems may be as high as 10,000 MVA. The ultimate limit in power transfer capability will be realized by the use of cryogenic cable systems. The cryogenic cables undergoing development can be devided into two basic types: namely, those in which the conductor operates in the superconducting mode (superconducting cables) and those in which the conductor operates in the reduced conductor resistance mode (cryo-resistive cables). In a recently developed prototype cryoresistive cable, spunbonded-polyethylene synthetic-paper tapes were used in conjunction with liquid nitrogen. Extremely low losses (tans - 10"°) were obtained and the resistance of the cable conductor was reduced by approximately a factor of 500 from that at room temperature. With cryoresistive cables power ratings up to 5000 MVA are contemplated. Initially super- 258

conducting cables were believed to bo necessarily restricted to ir-e under dc conditions- howover, the development of the niobium-tin sloy ci.ti-Juctor wnich exhibited supercond'.rtir.g properties {n the rony;? -f >-'-in f to i-jf'K with negligible magnetic loss at 60 Hz, has changed the situation entirely. Considerable work is underway to develop a suitable cable insulating system to be operative under liquid helium temperatures. There appear to be three main alternatives available - i.e. a conductor suspended by spacers in a liquid helium dielectric, a conductor insulated with a liquid helium impregnated dielectric or a conductor refrigerated by liquid helium and held in place by spacers in a high vacuum medium. The latter arrangement has the advantage of using less helium but suffers from suriace breakdown problems along the dielectric spacer surfaces. The power capacity of superconducting cables is projected into the area of 10,000 to 25,000 MVA. Superconducting cables could be operated at relatively low voltages (approx. 50 kV) due to their high current density capabilities; furthermore, unlike the cryoresistive cable design which uses impregnated synthetic paper tapes, not. only would the dielectric losses be low but also the capacitance/unit length would be low due to the unity dielectric constant value in the case of cables using the spacer design. Thus, superconducting cables could be used for long distance transmission, provided there would be sufficient supply of liquid helium available. Superconducting cables would become economical only at the high power ratings, where the refrigeration costs have been estimated to amount to only 15% of the total system cost.

We have not said much thus far about dc underground cables. The reason for this is that at the present, dc cables are used only under very special circumstances. They are primarily used as interties between isolated power networks and for submarine crossings where longer distances are involved. Unless the present preference for ac systems will abate with time, the use of dc cables is not expected to increase significantly. Before closing my remarks, I would like to add a few words on the transport of energy by fluids. C. TRANSPORT OF ENERGY BY FLUIDS, PARTICULARLY HYDROGEN. The cost of providing an energy supply is strongly influenced by the cost of delivering or transmitting the energy fr->m its source to its point of use. Moocm technology leans toward electrical energy as a means of supplying our increasing energy needs and toward nuclear-electric power as an ultimate substitute fur fossil fuel. Electric power, however, is a most expensive energy form to transmit and deliver and cannot readily be stored. A synthetic chemical fuel could be storable and cheaper to transmit. When we consider the various synthetic chemical fuels that could be made from nuclear power, hydrogen appears as the cleanest and simplest candidate for an energy-distribution medium. Its combustion products are compatible with the atmosphere. Hydrogen could, in principle, be distributed as universally a.s natural gas is today, using most of the same technology. But its use would present some new technological problems. It could do all of the jobs done by natural gas, and more. Its universal availability would 259

give rise to new technological opportunities. Hydrogen can be transmitted from the generating stations to the load centers in underground pipelines similar to those used for natural gas today. Many factors, such as cooling requirements and safety considerations force the optimum location of power stations to be very far from the load centers. Offshore locations are now seriously contemplated by sectors of the nuclear industry. Hydrogen is already routinely "pipelined" in many hundreds of refinery and chemical plant locations throughout the world at pressures up to 1200 psi, but for quite short distances. Pipelines carrying hydrogen over distances of up to 50 miles are in operation in the Houston, Texas, area. In the Ruhr area of Germany, a hydrogen delivery pipeline network extends for 130 miles. Much of this network has been in continuous operation since 1940. Energy can be transported concurrently by liquid hydrogen and by cryogenic cable. This combination would permit delivering hydrogen where the demand need not be met directly by electric power while reserving electric power for direct use. The combination will drastically reduce, and in the dc case will virtually eliminate cryogenic cable refrigeration even for superconducting lines, since heat flow from a surface at liquid hydrogen temperature (20°K) to helium is negligible. The economics of such a scheme have been studied, and it is proposed by Los Alamos engineers to service a system connecting New Mexico and Los Angeles. The wide experience available for the handling, transport and storage of hydrogen is presented by Bart!it et al. en o

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PROSPECTS FOR URBAN TRANSIT SYSTEMS

MALCOLM D. ARMSTRONG AND JOHN H. MORGAN

Transportation Development Agency (M.O.T.) Montreal

A brief examination of energy usage in Canada clearly shows just how significant a role transportation plays in the overall energy balance. Fig. 1 illustrates both the sources and end uses of energy on a nation-wide basis. Not only did transport account for 23.5% of the energy consumed in Canada in the year 1972, but it also accounted for 37.5% of the energy wasted. Any attempt to economize on energy consumption will have to reduce the overall amount of energy used by the transportation sector, and at the same time, convert the usage pattern to one where some of the exhaust heat energy could be recovered and utilized for other purposes. The latter point can be illustrated by the following example: if electricity wer the prime motive power for transportation, some arrangement could be made for the recuperation of waste heat at the power plant by using it for domestic and industrial heating applications. Under today's pricing conditions energy is a relatively cheap commodity and there is no particular incentive to develop methods of saving it.

The breakdown of energy consumed by the transportation sector is shown in Table 1. The private automobile is by far the largest consumer of fuel particularly when it is used in urban driving. It accounts for over one-third of the transportation energy consumed and if the fuel used in inter-city driving is added, the overall total is just short of 50% of the energy consumed. At the risk of belaboring the obvious, it should be pointed out that fuel usage or sqandering is by no means the automobile's sole or major sin. The pollution emitted by automobile exhausts is known to be a major contributor to urban air pollution. The distortions in land use resulting from the very widespread use of private automobiles not only in Los Angeles, but even in cities like Toronto, have been sufficiently well documented.

Fig. 2 shows the fuel usage in passenger-miles per U.S. gallon of various means of passenger transport. It is interesting to note that automobiies (taken in their broadest definition) span almost the entire range with the heavy limousine transporting only its driver at one end of the scale and a jammed micro-bus at the other extremity. The point here is that there is no justification for condemning the.automobile at all times. It would be difficult, indeed, to improve upon the family automobile when carrying two adults and 2.7 children on a trip to visit relatives be they 5 or 105 miles away. It would, howevers be very desirable to reduce the rather large number of people who drive their automobiles to work and leave them in "dead storage" throughout the working day and use them again to go home at night. ro ro

TABLE I FUEL USAGE IN TRANSPORTATION - CANADA - 1970

0/ Gasoline Diesel oil Heavy Fuel oil AVGAS & TOTAL fa GalsxlO6 GalsxlO5 GalsxlO6 Turbo Fuel GalsxlO6 GalsxlO6

Automobile - Urban 2,579.7 34 .5 - Intercity 1,101.8 '4 .7 - Total 3,690.5 3,690.5

True*c - Urban 734.3 164.1 12 .1 - Intercity 857.0 227.9 14 .3 - Total 1,591.3 392.0 1,983.3

Bus -• Urban 3.1 31.3 .5 • Intercity 3.0 16.1 .4 • Total 6.1 4T? 53.5

Rail - Passenger 61.4 .8 - Freight. 120.5 1 .6 - Package ?5o 5 3.4 - Total 44C.4 440.4

Marine - Domestic 93.9 200. C 3 .9 - Deep Sea 95.1 173.2 3 .6 - Total 189.0 '74.0 563.C

Air - Ai r Lines 730.5 9 .1 G.A. 38.9 .5 - Total 769.4 769.4 263

Number of passengers Obsolete systems S.S. "Queen Mary 1.600 1930V-16 -'Ian 2 1850 steam 'r ,iin 80 Double-deck urban bus 20 Current systems Cabin yacht 4 Helicopter 24 Automobile (urban us.) 1 Corporate je; 8 Modern cruise line '250 Pullman train 100

DC-8 jet 78 DC-6 .->•-..« 33 « -bo jet •3-747} 210 Tfc... 3 Ait. is (DC-10) 180 . "tciw Nto f'ltf' ' ge use) 2 **! .vste plane 3 U?va* bus (noon) 12 f».C.C. krcat car (noon) 36 • t-ifesteaaen "beetle" 2

tosi^t. Manchester train 400 T0-!cv*l commuter train 1.200 Highway bus 22 Motorcycle (2 h.p) 1 Volkswagen Microbus 7 Somt proposed systams: U.S. S.S.T. 150 250-m.p.h TACV 48 Tilt-wing VTOL 48 Urban menorsil (one car) 20 Net propulsion efficiency 80 160

Fig. 2 264

The next question that arises is: What can Technology do to bring about a significant decrease in the energy consumed by the transportation sector? Evolutionary developments in internal contusion engines will probably result in improvements in fuel consumption which will overcome the penalties resulting from the recently imposed pollution control devices, and thus continue the tendency toward overall improvement in fuel consumption. The increasing popularity of compact and sub-compact automobiles will also tend to reduce the per-vehicle rate of energy consumption. In terms of the total amount of fuel consumed, however, both of these tendencies towards fuel economy are very likely to be over- whelmed by the continuing increase in private vehicle registration. Fig. 2 also shows that the likelihood of achieving significant fuel economies from various new technologies is not great.

There is a role for innovation in urban transportation, however, and it lies much more in the soft and human areas. The only effective means of achieving overall energy economies is to provide within the public sector of both urban and inter-urban transportation systems sufficient incentive to persuade today's private automobile driver to make full use of public transportation systems. The sort of improvements likely to bring this about would cons.st of the following: "*. Higher block speeds between stations. 2. A demand-responsive arrangement for passenger pick-up.

3. A distribution system which will convey the passenger to .vithin reach of his place of work. 4. Sufficient frequency of service to minimize delays at either end of the journey. 5. Some modicum of comfort even when travelling at busy times of day. 6. A significant economy compared to travel by private automobile (such economies could, of course, be enhanced by arranging rather high user charges for parking space or use of urban roads within urban perimeters).

What is needed is something resembling the door-to-door convenience of the private automobile without the energy and land use penalties whic'i automobile usage engenders.

The first series of innovations will be evolutionary changes in existing means of transport. In most of these cases the technological aspects of the changes are not important - it is the structure of the overall traffic system that is altered in order to make the public transportation mode more effective. The Mercedes Benz Electro-Bus for 255 example is an interesting departure from the conventional because it offers three distinct modes of operation:

1. It can use its engine to drive its wheels directly (this is the mode offering the greatest fuel economy but causing some degree of pollution and is therefore intended for use outside cities).

2. It can run electrically from storage batteries.

3. Ix can use the diesel engine to charge the batteries. Another idea is the exclusive bus lane which is in use in Toronto and Calgary as well as in several of the tunnels leading into New York City. Exclusive bus lanes are one method of giving buses preference over private vehicles at bottle-necks particularly in the rush hour (the message to the private automobile driver would become clear enough if he saw dozens of buses passing him while he is immobile). An interesting option provided by the exclusive bus lane is that buses can use a lane running in a direction opposite to the other traffic on one-way streets.

The town of Runcorn has adapted a system of elevated roadways used by buses only, in order to eliminate conflict with other forms of traffic and so speed the movement of people by public transportation. The GO system in Southern Ontario is providing, on a limited scale, a demand-responsive service in which a traveller telephones the bus dispatcher to arrange for a minibus to pick him up at his doorstep within a given time span and to deliver him to the nearest GO-train station. When returning home the process is reversed and the minibus transports travellers from the GO station to their homes. The system is designed to provide service to the traveller approximating the convenience of the private automobile yet provided by the public utility. It is particularly effective in residential suburbs where traffic density does not warrant the maintenance of a scheduled bus service The Telebus system in Regina works on a similar basis. Both the GO and the Telebus service are due to be expanded in the near future.

The self-drive taxi was an idea tried out in Montpellier, France, where customer-operated taxis could be picked up and left anywhere within designated areas of the city. The purpose of the system was to reduce the number of automobiles parked in the city during the day. The car was electric to minimize pollution and was activated by a consumable token. North American manufacturers have also been experimenting with electric automobiles. It is also quite possible that, some sort of street-car will come back into use. The new street-cars will certainly be much more attractive and comfortable tuci theii predecessors. Although the engineering development of the street-car in Europe has been continuing, the more significant innovations ar* not mechanical, instead they consist of such things 266