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A quantitative analysis of some policy alternatives affecting Canadian natural gas and crude oil demand… McRae, Robert N. 1977

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A QUANT ETATIVE ANALYSIS OF SOME POLICY ALTERNATIVES AFFECTING CANADIAN NATURAL GAS AND CRUDE OIL DEMAND AND SUPPLY by Robert Norman McRae B.Sc, University of British-Columbia, 1970 M.Sc, University of British. Columbia, 1972 A thesis submitted in partial fulfilment of - the requirements for the degree of Ph..D. in the Department of Economics We accept this thesis as conforming, to the required standard: The University of British. Columbia March. 1977 Robert Norman McRae, 1977 < In presenting th i s thes is in pa r t i a l fu l f i lment of the requirements for an advanced degree at the Univers i ty of B r i t i s h Columbia, I agree that the L ibrary shal l make it f ree ly ava i l ab le for reference and study. I further agree that permission for extensive copying of th is thesis for scho lar ly purposes may be granted by the Head of my Department or by his representat ives. It is understood that copying or pub l i ca t ion of this thes is fo r f inanc ia l gain sha l l not be allowed without my written permission. Department of The Univers i ty of B r i t i s h Columbia 2075 Wesbrook Place Vancouver, Canada V6T 1W5 Date A j ^ J l IX, 1^?7> i i ABSTRACT Only recently has the Canadian federal government become involved in the regulation of energy prices. Since 1973 the federal government has imposed an export tax on crude o i l , set the wellhead price of crude o i l , implemented a one-price policy for domestic crude o i l , regulated the Toronto city-gate price of natural gas, and increased the export price of natural gas. The federal government has also been involved in restricting the flow of energy quantities, mostly i n the export market. The lack of rigorous economic analysis of the implications of these and other policy recommendations,, as contained in various reports by the Department of Energy* Mines and Resources and the National Energy Board, motivated me to build an economic policy-oriented model describing some aspects of Canadian energy demand and supply. The demand part of the model contains a set of estimated equations that describe the demand for crude o i l , natural gas, e l e c t r i c i t y and coal within each of the five major consuming regions - Atlantic, Quebec, Ontario, Prairies, and B.C. A change in any energy price through govern-ment regulation w i l l induce interfuel substitution and alter the mix of energy fuels demanded. To forecast future energy demand, the parameters estimated from h i s t o r i c a l experience are used in conjunction with fore-casts of the exogenous variables, the latter usually obtained from government sources. The resulting "base-case" forecast of energy demand is compared with the forecasts by the National Energy Board and the Department of Energy, Mines and Resources. The supply side of the model considers only the supply of crude o i l and natural gas. The output of these fuels can be affected through any policy which affects either the amount of fuel demanded by Canadians or the amount of fuel demanded in the export market. An interesting component embedded i n the supply -model for crude o i l is the Sarnia-Montreal pipeline. The flow through the Sarnia-Montreal o i l pipeline can. be altered i n the model to examine certain trade-off p o s s i b i l i t i e s between imports and exports of crude o i l . The supply model for both crude o i l and natural gas contains details relating to production, exploration, development, costs, taxes, royalties, and the distribution of economic rents among producers, consumers and governments. The complete model i s used to provide results of some sensitivity experiments and some policy experiments. The sensitivity experiments Involve altering the basic assumptions with regard to the grox^th of real gross national expenditure, the offshore o i l price and the efficiency factors for o i l and gas use. The policy experiments focus on three main areas: the pricing of o i l and gas, the trading of o i l and gas, and the eastward flow through the Sarnia-Montreal o i l pipeline. I believe that the dissertation provides three main contributions I believe that the specification and estimation of the aggregate demand system is a useful contribution. I believe that the process of building a model which, integrates the supply and demand relationships, and details the costs, rents and trade flows for both crude o i l and natural gas has been successful. And I have Been successful in using the integrated energy system to generate quantitative results under alternative policies. Acknowledgement To an excellent adviser and a good f r i e n d : thank you, John H e l l i w e l l . I wish to thank John for suggesting my research t o p i c , for encouraging and a s s i s t i n g i n i t s long development, and for generously giving his time for discussing and a r r i v i n g at ingenious solutions to my problems, I also wish to acknowledge the helpful discussions provided by my other two committee members: Ernie Berndt and Paul Bradley; and by the other members of my departmental examining committee: Anthony Scott, Terry Hales and Milton Moore. Of course, I accept the r e s p o n s i b i l i t y for any errors contained within the thesis. I would l i k e to acknowledge f i n a n c i a l support from the Canada Council and from the Dafoe Foundation. I am indebted to the Computing Centre at a.B.C. for maintaining a superb computer environment, which I used extensively. iv TABLE CF CONTENTS 1. Introduction ........................................... 1 2. Energy Demand Model 7 2.1 Summary of Some Previous Demand Studies ............ 8 2.2 The Formulation of the Demand Model ...12 2.3 Structure of the Estimation Equations and Data '16 2.4 The Technigues Used During Estimation ,.29 2.5 The Forecast Results Using the Demand Model ........34 2.6 A Comparison of My Demand Forecast with Others .....36 3. Modelling the Supply of Crude O i l and Natural Gas .48 3.1 The Production of Crude O i l and Natural Gas ........49 3.2 Development of Natural Gas and Crude O i l Resources..53 3.3 Exploration for Crude O i l and Natural Gas Reserves..57 3.4 The Economic Regulation of Crude O i l and Natural Gas Supply .. .,64 4. Non-frontier Natural Gas Production .......65 4.1 A Description of the Production Process ............ 66 4.2 A Description of the Price and Cost Variables ...... 71 4.3 -A Description of the Tax and Rent Equations ........ 75 5. Non-frontier Conventional Crude O i l Production .........81 5. 1 A Description of the Production Process ............82 5.2 A Description of the Price and Cost Variables ......88 5.3 A Description of the Tax and Rent Equations .........91 6. Policy Analysis 93 6.1 Background l i t e r a t u r e on Trade and Price P o l i c i e s ..96 6.2 The Simulated Energy Demand E l a s t i c i t i e s ........... 103 6.3 A S e n s i t i v i t y Analysis of Some Factors Affecting the Demand System 109 6.4 An Analysis of Some Energy Pr i c i n g P o l i c i e s . . . . . . . . . 115 6.5 An Analysis of Some O i l and Gas Export P o l i c i e s . . . . . 119 6.6 An Analysis of Alternative Montreal Pipeline Flews..122 7. Summary 124 References 135 V TABLE OF APPENDICES 1. L i s t of Variables, C o e f f i c i e n t s , and Definitions ....... 147 1.A Demand Sector 147 1.E Ncn-frontier Natural Gas Production 155 1.C Non-frontier Conventional Crude G i l Production ..... 157 1. D Fuel Losses and Energy Supply Use .................. 159 2. Model Eguations 160 2. A Demand Sector 160 2.B Non-frontier Natural Gas Production ................ 174 2.C Ncn-frontier Conventional Crude O i l Production ......182 2. D Fuel Losses and Energy Supply Use 190 3. Description of the Demand Sector 191 3. A Derivation of Cost Share Equations .............193 3.E Parameter Estimates of Demand Eguations .............195 3.C Btu Ef f i c i e n c y Conversion Factors 220 3.D Estimated Eguations for Energy Supply Use and Losses 223 3. E Construction of Energy Quantities and Prices ........ 225 4. Description of Non-frontier Gas and O i l Production ......240 4. A The Construction of Some Series Used ................240 4.B The Construction of Reserve Costs 244 4.C The Sources for the Co e f f i c i e n t s Used ...............254 4. B The Description of the Taxation and Royalty System ..258 5. The Base Case Model Forecast ...261 5. A Assumptions Used to Produce the Ease Case Forecast ..261 5..B Results of the Base Case Forecast 264 6. The S e n s i t i v i t y and Policy Experiments .................. 272 6.A Description of S e n s i t i v i t y and Policy Experiments ...272 6.B Results of the S e n s i t i v i t y and Policy Experiments ...273 vi TAEIE OF FIGURES Figure 1: Canadian Energy Demand Divided by Region............... 128 Figure 2: Shares cf Primary Fuels i n Canadian Energy Demand .....129 Figure 3: Current $ Expenditure on Energy Accumulated by Region 130 Figure 4: Natural Gas Demand and Non-frontier Production ........ 131 Figure 5: Crude O i l Demand, Production and Flow Through the Montreal Pipeline ...........132 Figure 6: Shares of Primary Fuels Demanded Before and After a 15% F a l l i n the Gas Price 133 Figure 7: Primary Fuels Demanded Before and After a 15% F a l l i n the Gas Price 134 1 1. Introduction Only recently has the Canadian federal government become involved i n the regulation of energy prices. Since late 1973.the federal government has imposed an export tax on crude o i l , set the wellhead price of crude o i l , implemented a one-price policy for domestic crude o i l , regulated the Toronto city-gate price of natural gas, and increased the export price of natural gas. The federal government has also been involved i n r e s t r i c t i n g the flow of energy guantities, mostly i n the export market. The Canadian government, on the recommendation of. the National Energy Board, has refused since 1970 to issue any new export permits for natural gas and has agreed to a rapid phase-out of a l l exports of crude o i l after November 1974, The Canadian government i n s i s t e d that a pipeline extension from Sarnia to Montreal be b u i l t for the purpose of using western Canadian crude o i l to displace some imports by mid-1976. But the lack of a rigorous economic analysis of the implications cf policy recommendations contained in recent publications by the National Energy Board [34,35,36] and the Department of Energy Mines and Resources [31] has motivated me to build an economic policy-oriented model describing Canadian energy demands and 2 sup p l i e s . 1 The la t e s t report by the Department of Energy Mines and Resources [32] i s more thorough than any of the previous government publications in specifying the economic implications of policy a l t e r n a t i v e s , and hence provides results which are useful for comparison. In section 2.6 the r e s u l t s of the base case demand forecast are compared with those of the Department of Energy Mines and Resources. The Department of Energy Mines and Resources report has only two basic scenarios: a high price and a low price experiment (although high and low a c t i v i t y experiments are sometimes reported). However, the demand model used in the Department of Energy Mines and Resources study i s unable to predict endogenously the t o t a l impact on i n t e r f u e l substitution caused by changes i n r e l a t i v e energy prices. The report, nevertheless, recognizes that p r i c i n g options are important: "...to the degree that governments control the prices of o i l and natural gas d i r e c t l y and exercise substantial influence on the price of e l e c t r i c i t y and coal, p r i c i n g policy can be used to f a c i l i t a t e the substitution of one energy source for another" [32, p.136]. I intend to experiment with a wider range of policy alternatives than was considered in the Department of Energy Mines and Resources study. 1 I have been responsible for most of the development work on the demand sector, the non-frontier conventional crude o i l production sector and the non-frontier natural gas production sector. Within the production sectors, the taxation and royalty equations i n the post-1973 period are the work of Bruce Duncan. The modelling of the f r o n t i e r Mackenzie natural gas sector and the non-conventional Alberta o i l sands sector has been done by others, but i s compatible with the modelling environment used for my sectors. 3 In the introduction, a very broad outline i s provided i n d i c a t i n g what the model does and how i t works. Chapters 2 to 5 contain descriptions of the main sectors. In chapter 6 I analyse the kind of policy alternatives for which the model can be used. The l a s t chapter provides a summary of the work. The s i x appendices provide a l l of the variable names, eguations, data sources and detailed descriptions of the demand model, non-frontier natural gas model, non-frontier conventional crude o i l model, the base case model solution, and the policy a l t e r n a t i v e s . Before describing, in rather general terms, the major sectors of the model, the nature of a simulation system w i l l be explained. The following d e f i n i t i o n w i l l be used for the process of simulation: Simulation i s a numerical technique for conducting experiments on a d i g i t a l computer, which involves cer t a i n types of mathematical and l o g i c a l models that describe the behaviour of a business or economic system {or some component thereof) over extended periods of re a l time. [114, p. 3]. A simulation process 2 i s used because the model contains a large number of simultaneous eguations and must be solved over an extended period of time. The simulation process makes i t possible to solve complex systems over time, and to study the e f f e c t s on the system's behaviour due to policy changes in the structure of the model. In an attempt to be more s p e c i f i c about what i s meant by a simulation model the following d e f i n i t i o n i s used: 2 The numerical technigue used in the solution of the simulation process i s the Gauss- Seidel i t e r a t i o n process, described i n the Bank of Canada publication, Simulator (1972). 4 A s c i e n t i f i c model can be d e f i n e d as an a b s t r a c t i o n of some r e a l system t h a t can be used f o r the purposes of p r e d i c t i o n and c o n t r o l . The purpose of a s c i e n t i f i c model i s t o enable the a n a l y s t to determine how one or more changes i n aspects of a modeled system may a f f e c t other a s p e c t s of the system or the system as a whole. [ 1 1 4 , p . 9 - 1 0 ] . Any s i m u l a t i o n model must embody two opposing a t t r i b u t e s -s i m p l i c i t y and r e a l i s m . As the reader examines the s i m u l a t i o n model i n more d e t a i l , he can judge f o r himself whether I have s t r u c k an a c c e p t a b l e compromise between s i m p l i c i t y and r e a l i s m . In the design and o p e r a t i o n of the model, s p e c i a l a t t e n t i o n i s paid to energy trade and t r a n s p o r t a t i o n , and to the c u r r e n t r o l e of domestic crude o i l and n a t u r a l gas p r i c e s as key elements i n the f e d e r a l government's energy p o l i c y . Horld crude o i l p r i c e s are t r e a t e d as being determined o u t s i d e Canada, and c i t y - g a t e Toronto n a t u r a l gas p r i c e s and wellhead crude o i l p r i c e s as being determined by some p o l i c y r u l e . The r e l e v a n t t r a n s p o r t c o s t s are then added or s u b t r a c t e d to o b t a i n the crude o i l and n a t u r a l gas p r i c e s a p p l i c a b l e i n each of Canada's f i v e consuming r e g i o n s (B.C., P r a i r i e s , O n t a r i o , Quebec, and A t l a n t i c ) . These p r i c e s are then used w i t h i n a c o n s i s t e n t s e t of estimated demand eguations to o b t a i n f o r e c a s t s of demand f o r each of fou r primary energy sources ( i n c l u d i n g c o a l and e l e c t r i c i t y i n a d d i t i o n to crude o i l and n a t u r a l gas) w i t h i n each of the f i v e r e g i o n s . More d e t a i l s on the demand s e c t o r are contained i n chapter 2. Given a f o r e c a s t f o r crude o i l e x p o r t s , the e x p l i c i t treatment of the flows through the Montreal p i p e l i n e , and the r e g i o n a l demands f o r crude o i l , the model can determine the crude o i l imports i n t o e a s t e r n Canada and the amount of s h u t - i n crude o i l producing c a p a c i t y i n Western Canada; or, i n l a t e r 5 years, the amount by which National Energy Board forecasts of crude o i l production f a l l short of demand west of the Ottawa Valley l i n e , thus requiring westbound flows through the Montreal pipe l i n e . These crude o i l flows are also affected by the amount ft of synthetic o i l produced, as modelled in the o i l sands sector. k detailed description of the non-frontier conventional crude o i l sector i s contained i n chapter 5. Canadian demands for natural gas are combined with exports under e x i s t i n g contracts to give a requirements series that i s met from non-frontier and f r o n t i e r sources, depending on the assumptions made in the a r c t i c pipeline sector about the timing and extent of a r c t i c development. I f demand exceeds supply there i s no automatic trade flow to make up the shortage, as there i s in the case of crude o i l . Thus the preparation of an integrated and consistent natural gas forecast may require a l t e r i n g the price p o l i c i e s or obtaining access to f r o n t i e r supplies to avoid potential shortages. Chapter 4 contains the d e t a i l s about the non-frontier natural gas sector. The model contains considerable d e t a i l in the tax and royalty arrangements that d i s t r i b u t e , i n conjunction with energy price p o l i c i e s , the economic rents from energy resources among producers, consumers, and governments. Past costs, revenues, and tax structures have a l l been considered, so that the t o t a l f i n a n c i a l history of the conventional o i l and gas industries can be assessed. This accounting over a ' f u l l c y c l e ' of investment i s important i n extractive industries where exploration and development expenditures can precede production by many years. These timing relationships are complex enough to make simulation / / / 6 necessary for accurate measurements of the effects of alter n a t i v e p o l i c i e s . In chapter 6, I provide an analysis of some s e n s i t i v i t y experiments on various important exogenous variables in the demand model, and an analysis of some policy experiments. The s e n s i t i v i t y experiments involve a l t e r i n g the standard assumptions with regard to the growth i n real GNE, the offshore o i l price and the e f f i c i e n c y factors for o i l and gas. The policy experiments focus on three main areas: the pricing of o i l and gas, the trade of o i l and gas, and the eastward flow through the Sarnia-Montreal pipeline. The assessment of the future e f f e c t s of p o l i c i e s , reported i n chapter 6, must be regarded as tentative, for one i s s t i l l forced to rel y on second-hand forecasts of the l i k e l y flows of conventional crude o i l and natural gas from established reserves, and on the l i k e l y guantities of new crude o i l and natural gas discoveries i n non-frontier regions. In addition, the estimates of the r i s i n g costs of new non-frontier crude o i l and natural gas reserves are very approximate and based on h i s t o r i c a l data which may be inappropriate for the forecast period. Despite a l l of these shortcomings, the model does provide a valuable device for integrating the many strands of energy policy that are otherwise l i k e l y to be treated by p a r t i a l and inconsistent analysis. 7 2, Energy Demand Model Expected demands for primary energy fuels i n Canada w i l l play a pivotal r o l e i n assessing Canadian energy policy. For instance, forecasts of both Canadian demand f o r natural gas and d e l i v e r a b i l i t y of natural gas from the non-frontier producing regions w i l l be important in determining the optimum date for de l i v e r i n g f r o n t i e r sources of natural gas to Canadian markets. The primary fuels considered are crude o i l , natural gas, e l e c t r i c i t y and coal. But the demand for any single f u e l cannot be examined in i s o l a t i o n . The existence of substitute energy sources, and of substitutes for energy i t s e l f , implies that a system of i n t e r - r e l a t e d demands must be examined. The development of t h i s chapter i s separated into six sections. In section 2.1 an evaluation and summary of some previous demand studies i s provided. The assumptions behind the formulation of the demand model are contained i n section 2.2. The next two sections contain the d e t a i l s about the construction of the data, the structure of the estimation eguations, and the estimation technigues. In section 2.5 the underlying forecast assumptions and forecast results are b r i e f l y described. The l a s t section contains a comparison of my demand forecast with forecasts by the National Energy Board and Department of Energy Mines and Resources. 8 2.1 Summary of Some Previous Demand Studies Host studies on the economics of the petroleum sector have focused on problems of supply. But the demand for crude o i l and natural gas must also be examined. Some ad hoc studies of demand extrapolate h i s t o r i c a l trends i n energy growth (National Energy Board [ 33,34,36]). Other studies use the assumption that the trend i n the energy-GNP r a t i o i s constant (Darmstadter [45]). I t has been pointed out by Berndt [16] and Mitchell [112] that one must consider r e l a t i v e prices and income in order to predict the demand for energy. 3 There has been quite a l o t cf research analysing the demand for a certain fuel in a certain sector of the economy (Balestra [11,12], Baxter and Rees [14], Khazzoom £95,96], and Mount, Chapman and T y r r e l l [113]). Recently there has been a f l u r r y of research considering the. demand for a l l substitutable energy products by end-use sector (Fuss, Hyndman and Haverman [60], Gorbet [63], and Hunt and Smith [87]); and also considering the demand for energy as a derived factor demand from a production function (Berndt and Wood [15], Fuss et a l [60], and Humphrey and Moroney [86]). A paper by Berndt and Wood [15], investigating the United States manufacturing industry, seemed to star t the trend towards research e x p l i c i t l y testing for c r o s s - s u b s t i t u t a b i l i t y between energy and non-energy inputs. The res u l t s show that energy i s 3 I s h a l l use the terminology 'demand for energy' to mean the demand for an aggregate of f i n a l end-use energy products. Shenever the demand for crude o i l , natural gas or other raw products i s being discussed I s h a l l use the terminology 'demand for primary energy products'. 9 responsive to i t s own price, that energy i s s l i g h t l y substitutable with labour, and that energy i s complementary with c a p i t a l . The following i s a brief description of the two most comprehensive models of Canadian demand for energy. The study by Fuss, Hyndman and Waverman [60] u t i l i z e s the same method as Berndt and Hood, using data for the Canadian manufacturing industry. Their r e s u l t s d i f f e r guite remarkably: i n Canada energy and c a p i t a l are found to be substitutes rather than complements, and energy and labour are found to be much more substitutable [60, p.26, table 8]. But they have extended the Berndt-Wood approach by calcu l a t i n g a share matrix consistent with the production function for each energy type i n the manufacturing sector. The micro-specification i s weaker in the r e s i d e n t i a l and commercial sector. A l o g i t model i s used in the r e s i d e n t i a l sector to estimate the shares of each f u e l , given the output of the sector and r e l a t i v e prices; a linear demand function i s used in the commercial sector to estimate the t o t a l demand for energy , It would be very d i f f i c u l t to use their r e s u l t s to arrive at an aggregate consumption of primary energy products because the i n d u s t r i a l sector i s represented by only manufacturing, the commercial sector has no f u e l shares estimated, and the transportation sector i s absent. Gorbet [63] generally uses a l o g - l i n e a r form of regression eguation to establish a rel a t i o n s h i p between aggregate energy 10 demanded* and aggregate a c t i v i t y and price variables f o r the commercial, i n d u s t r i a l and r e s i d e n t i a l end-use sectors treated separately. The model then feeds the calculated t o t a l energy demand for each sector through a matrix of projected "market shares which seem consistent with anticipated developments in technology and r e l a t i v e prices of alternative energy sources" [63, p.15] i n order to arr i v e at demands f o r s p e c i f i c energy products. 5 The l a s t step in the model i s to use fixed c o e f f i c i e n t s to estimate the Btus of coal, natural gas and fu e l o i l which are necessary to produce the projected use of e l e c t r i c i t y (net of hydro and nuclear generated e l e c t r i c i t y ) summed over a l l end-use sectors. This model goes a long way toward deriving the demand for primary energy products from the demand for energy i n the end-use sector. However, the transportation end-use sector has not yet been completed, and the market share matrix has not yet been estimated using the same prices which appear as exogenous variables i n the regression eguations. This inconsistency could lead to incorrect r e s u l t s when the model i s subjected to price shocks. In the l a s t step of the model, there i s no transformation of the demand for refined products into a demand for crude o i l . These models may be unreliable to the extent that they are s t a t i c , which assumes that adjustment of energy demand takes * For each of the f i v e regions used in the analysis the t o t a l energy consumed, measured in 'input Btus', was converted to energy actually u t i l i z e d , measured i n 'output Btus'. The conversion was necessary because various fuels which compete i n the same end-use sector have d i f f e r e n t e f f i c i e n c y f a c tors. 5 The predicted output Btus by energy product are converted back to an input Btu measure by applying the same u t i l i z a t i o n e f f i c i e n c y factors used before. 11 place within one period (year). For abrupt and large changes i n r e l a t i v e prices, technology or tastes a dynamic model should be used. Gorbet claims that as far as adjustment lags are concerned "most people agree that the approach to equilibrium i s guite protracted since the process of adjustment e n t a i l s replacing existing c a p i t a l appliances with more energy e f f i c i e n t appliances" [63, p. 10 ]. Another perplexing problem which must be faced i s how confident one can be in using e l a s t i c i t y estimates derived from a period of gradually f a l l i n g r e l a t i v e energy prices to a future period characterized by increasing r e l a t i v e energy prices. A major b a r r i e r to a symmetric response would be the i m p o s s i b i l i t y of immediate replacement of c a p i t a l stock. 12 2.2 The Formulation of the Demand Model Two major c r i t e r i a were used to formulate the demand model used in t h i s study: the model must explain the interdependence of fuel demands, and the parameters of the model must be derived empirically. The f i r s t c r i t e r i o n i s based on the assumption that market developments a f f e c t i n g the price of crude o i l , e l e c t r i c i t y or coal can influence the l e v e l of demand for natural gas. The second c r i t e r i o n requires that the model be designed to make use of available data. In our case the data cover the period 1958-1973; and most of i t has been obtained from S t a t i s t i c s Canada publications, as described i n appendix 3. It i s hypothesized that e l e c t r i c i t y or crude o i l products can be substituted for natural gas i n mcst markets where natural gas i s sold; and that coal and crude o i l products can be used as substitutes f o r natural gas i n the generation of thermal e l e c t r i c i t y . It i s assumed that coal w i l l not compete as a substitute i n most domestic markets (except for thermal e l e c t r i c i t y generation). Only for a small part of Ontario i n d u s t r i a l demand i s t h i s assumption about coal l i k e l y to be inappropriate. although i t i s only the wellhead demands for crude o i l and natural gas which are needed for the policy analysis i n the t h e s i s , the s u b s t i t u t a b i l i t y of energy products requires a framework in which the demand for a l l energy products must be considered. The demand for energy i s e s s e n t i a l l y a derived demand for an intermediate product: hence given the desired output, the r e l a t i v e prices of a l l factor inputs, and the degree 13 o f s u b s t i t u t i o n p o s s i b i l i t i e s among i n p u t s allowed by technology one can determine the demand f o r energy. A r i g o r o u s approach to the demand f o r energy would execute such an a n a l y s i s f o r each of the major end-use s e c t o r s : commercial, r e s i d e n t i a l , i n d u s t r i a l and t r a n s p o r t a t i o n . Then w i t h i n each end-use s e c t o r the t o t a l demand f o r energy would be decomposed i n t o the demand f o r the r e l e v a n t energy products v i a a share matrix which s i g n i f i e s the i n t e r f u e l s u b s t i t u t a b i l i t y . T h i s l e v e l of d i s a g g r e g a t i o n i s a t t r a c t i v e i f the energy users are r e a c t i n g t o a d i f f e r e n t set of v a r i a b l e s , d i f f e r e n t s u b s t i t u t i o n p o s s i b i l i t i e s , or d i f f e r e n t r e l a t i v e p r i c e s i n d i f f e r e n t end-use s e c t o r s . The demand modal presented below i s more aggregated than the i d e a l model d i s c u s s e d above. But i t i s hoped t h a t the assumptions necessary t o formulate the aggregate model are t h e o r e t i c a l l y and e m p i r i c a l l y reasonable. Most of the assumptions are due to data l i m i t a t i o n s . I t i s assumed that the aggregate production f u n c t i o n i n each of the end-use s e c t o r s i s weakly separable i n i t s energy i n p u t s : i . e . , the production f u n c t i o n f o r s e c t o r s, Qs = Qs ( E1,. .. , En #K ,.L,&) , can be r e w r i t t e n as 2s = Qs ( E (E1,..,,En), K, L, M), where Qs i s the output, E(E1,...,En) i s an aggregate f u n c t i o n f o r a l l the energy i n p u t s E i , K i s the aggregate c a p i t a l i n p u t , L i s the aggregate labour i n p u t , and fl i s the i n t e r m e d i a t e input. The weak s e p a r a b i l i t y assumption means that the marginal r a t e of s u b s t i t u t i o n between E i and E j i s independent of the g u a n t i t i e s of K and L demanded. The assumption about the weak s e p a r a b i l i t y of energy i s a l s o made by Fuss, Hyndman and Haversian [60] using Canadian data and 14 by Hudson and Jorgensen [85] using U.S. data. However, the empirical findings of Berndt and wood [15], using aggregate U.S. manufacturing data, reject the v a l i d i t y of the weak s e p a r a b i l i t i y assumption for energy at the 99% confidence l e v e l . Since there has been no evidence rejecting the weak sep a r a b i l i t y assumption for energy using Canadian data, the assumption was used in order to simplify the analysis. It i s assumed that the aggregate energy production function i s continuously twice d i f f e r e n t i a b l e and exhibits constant returns to scale, which implies that one can use the duality between cost and production to demonstrate the existence of a cost function, Cs = Cs ( PE1,...,PEn,Zs) , where Cs i s the t o t a l energy cost, Zs i s the aggregate energy input, and PEi i s the price of the i ' t h energy f u e l . It i s assumed that the parameters associated with the aggregate energy cost function are the same i n each of the end-use sectors, which permits the estimation of only one energy cost function. Hence the data f o r each energy f u e l have been aggregated over a l l end-use sectors. Therefore the substitution p o s s i b i l i t i e s which are derived from the model w i l l be an average for the f u e l . Since the data cannot be broken down any further than the major end-use sectors ( r e s i d e n t i a l , commercial, i n d u s t r i a l and transportation), aggregation has already made i t impossible to determine substitution between fuels demanded for the same ultimate use of energy, mainly for heat or l i g h t . The assumption that a fuel reacts s i m i l a r l y across sectors to the same set of exogenous prices has i t s main weakness i n the fact that the f u e l prices are assumed to be the same in a l l sectors. It i s well known that natural gas and 15 e l e c t r i c i t y rates vary among di f f e r e n t classes of users (mostly through d i f f e r e n t two-part rate schedules); and a d i f f e r e n t set of crude o i l products (with t h e i r d i f f e r e n t prices and excise taxes) are used i n each end-use sector. Price differences across end-use sectors may also arise due to d i f f e r e n t wholesale and r e t a i l margins. It i s primarily because data are not available to derive a l l of the fu e l prices in each of the end-use sectors i n each of the f i v e regions in Canada over time that the assumption has been made to use 'city-gate' or 'refinery-gate' primary product prices. It i s hypothesized that estimating the substitution p o s s i b i l i t i e s among the primary fuels using city-gate prices w i l l approximate the average substitution of the f u e l over a l l the end-use sectors, A disadvantage i n not working backward from the end-use sectors i s that the structure lacks richness: for instance, i t i s impossible to assess the impact of the energy p o l i c i e s on the demand i n various end-use sectors. Since the major aim of the disser t a t i o n i s to examine the Canadian government p o l i c i e s as they a f f e c t the price and guantity of o i l and natural gas i n crude form, I am content with estimating d i r e c t l y the demand for crude products. 16 2.3 Structure of the Estimation Eguations and Data For estimation purposes the functional form of the energy cost function i s chosen to be the translog. The translog function has been discussed by Christensen et a l [41] and u t i l i z e d empirically for energy studies by Atkinson and Halvorsen [10], Berndt and Wood [15], Fuss et a l [60], Hudson and Jorgensen [85], and Humphrey and Horoney [86]. The advantage of the translog function over the t r a d i t i o n a l double logarithm demand eguation i s that the e l a s t i c i t y of substitution among commodities i s not constant and egual to unity. The disadvantage of using this functional form i s that i t i s very d i f f i c u l t to formulate a stock adjustment model. The translog i s one of several general formulations which place no r e s t r i c t i o n s on the Allen p a r t i a l e l a s t i c i t i e s of substitution, and can be interpreted as a second order approximation to any a r b i t r a r y twice-differentiable cost function. The assumption of cost minimizing behaviour, with input prices and output taken as given, and of certain r e g u l a r i t y conditions on the cost function (non-negative, l i n e a r homogenous in prices, and concave) implies input demand eguations with the dependent variable being the cost share: i . e . S i = PEi*Ei/C = a i + sum(j=1,n) b i j * l n P E j , i=1,...,n ..The system of share eguations i s constrained by certain parameter r e s t r i c t i o n s (which are not a l l independent): l i n e a r homogeneity i n prices implies that sum(j=1,n) b i j = 0; symmetry implies that b i j = b j i ( i , j= 1,. .. , n) ; and the, unity of the cost share summation Implies that sum(i=1,n) b i j = 0 and sum(i=1,n) a i = 1. 17 The derivation of the estimated cost share equations, with the above r e s t r i c t i o n s imposed, i s detailed in appendix 3,A; and the paramater estimates of the cost share eguations are detailed in appendix 3.B. It i s useful to know that one can derive the Allen p a r t i a l e l a s t i c i t i e s of substitution (oij) and the price e l a s t i c i t y of demand (nij) very e a s i l y by using the parameter estimates from the translog cost share eguations. The following formulae indicate how the summary measures are calculated: o i i = < b i i + S i 2 - Si ) / S i 2 , o i j = ( b i j + Si*Sj ) / S i * S j , n i i = S i * o i i , n i j = S j * o i j . The calculated own and cross price e l a s t i c i t i e s of demand are contained in appendix 3.B. In order to increase the number of observation points ' available for estimation, and in order to explain regional differences in energy usage, pooled cross-section and time series data were used from 1958 to 1973 for f i v e regions in Canada. These regions are A t l a n t i c , Quebec, Ontario, P r a i r i e s and B.C. 6 Yukon. Data on the guantity cf each of the primary fuels in each region are available i n a S t a t i s t i c s Canada document, e n t i t l e d Detailed Energy Sujrplv. and Demand i n Canada. The only data available on the corresponding prices are average prices obtained by dividing t o t a l expenditure by the quantity purchased. A l l of these average prices have been obtained from various S t a t i s t i c s Canada publications, as documented i n appendix 3-E. Some of these average prices are wellhead prices, which must be transformed into market prices by adding the transport t a r i f f . Data for crude o i l transportation t a r i f f s have been obtained from the Canadian Petroleum Association, 18 S t a t i s t i c a l Yearbook up to 1971. The lack of readily available data for natural gas and coal transportation t a r i f f s has led to the assumption that during the estimation period the t a r i f f s have been constant i n nominal terms. 6 From the available data the e l e c t r i c i t y price can be derived only i n the r e t a i l market, whereas a l l other prices are measured i n the wholesale (city-gate) market. A transformation c o e f f i c i e n t f or the price of e l e c t r i c i t y i s derived using an average of the transfer price between Ontario Hydro and Toronto Hydro. A l l of the prices and quantities have been adjusted so that they are measured in units c a l l e d •output* Btu. This unit i s created i n two stages: f i r s t the natural units are converted in t o •input' Btu, using the conversion factors reported by S t a t i s t i c s Canada. Then the input Btu are converted to output Btu using factors which capture the r e l a t i v e e f f i c i e n c y of energy conversion among the diff e r e n t fuels and appliances used i n the same end-use sector. These e f f i c i e n c y f a c t o r s , which are taken to be constant over time and region, were derived from a study by Gorbet for the Department of Energy, Mines, and Resources [63]. The methodology and data are contained in appendix 3.C. Even though the only end-use u t i l i z a t i o n e f f i c i e n c y factors at my disposal are constant over time and region, the derived average fuel e f f i c i e n c y factors do vary by region and over time * Since I have only been able to find natural gas t a r i f f rates for a few years t h i s assumption was neccesary, but i t i s not an unreasonable approximation to the actual behaviour of t a r i f f s , as i s shown in H e l l i w e l l and Lester [78]. Details are contained i n appendix 3.E. 19 because of d i f f e r e n t f u e l usage ac r o s s region and s h i f t s i n f u e l usage over time. By examining Table 3 i n appendix 3.C i t i s p o s s i b l e to compare the average e f f i c i e n c y of f u e l usage a c r o s s r e g i o n and over time. The e f f i c i e n c y of e l e c t r i c i t y does not vary over time or r e g i o n because i t i s e g u a l l y e f f i c i e n t i n a l l end-use s e c t o r s . Over time the average use of o i l and n a t u r a l gas has become more e f f i c i e n t i n the A t l a n t i c , Quebec and On t a r i o r e g i o n s . In the P r a i r i e s the e f f i c i e n c y of o i l has f a l l e n s l i g h t l y over time and remained constant f o r n a t u r a l gas; and i n B.C. the e f f i c i e n c y of o i l has remained constant over time and i n c r e a s e d s l i g h t l y f o r n a t u r a l gas. The s l i g h t i n c r e a s e over time i n the e f f i c i e n c y of o i l and n a t u r a l gas i m p l i e s a combination of a s h i f t to a l a r g e r market share f o r the i n d u s t r i a l and commercial end-use s e c t o r s , and a s h i f t i n usage away from l e s s e f f i c i e n t f u e l s . The reverse i s true f o r o i l e f f i c i e n c y i n the P r a i r i e s . The s h i f t i n f u e l shares toward the i n d u s t r i a l and commercial s e c t o r s i s r e p o r t e d i n Corbet [ 6 3 ] and Berndt [17], Across r e g i o n s the e f f i c i e n c y of o i l usage i s h i g h e s t i n Quebec, s l i g h t l y lower i n the A t l a n t i c and O n t a r i o , m a r g i n a l l y lower i n B.C., and g u i t e a b i t lower i n the P r a i r i e s . The o i l e f f i c i e n c y i n the P r a i r i e s i s the lowest because the r e g i o n consumes the l a r g e s t share of crude o i l products i n the form of d i e s a l o i l . Across r e g i o n s the e f f i c i e n c y of n a t u r a l gas usage i s highest i n Quebec, m a r g i n a l l y lower i n Ontario and s l i g h t l y lower i n the P r a i r i e s and B.C. The n a t u r a l gas e f f i c i e n c y i s s l i g h t l y higher i n Quebec and O n t a r i o because a r e l a t i v e l y l a r g e r share i s used i n the i n d u s t r i a l s e c t o r . The s t r u c t u r e of the demand model r e g u i r e s two s e t s of 20 estimation eguations. The set of eguations accounting for the interdependent nature of the system consists of f u e l cost share eguations. The other set of equations determines the aggregate expenditure on t o t a l energy in each region. The amounts of each f u e l used to generate thermal e l e c t r i c i t y have been removed from the main demand equations described above. This has been done to avoid double-counting both the thermal e l e c t i c i t y and the fuels used to generate i t . In order to estimate the guantities of f u e l used to generate thermal e l e c t r i c i t y , an a u x i l i a r y demand model of s i m i l a r design was used: i . e . i t consists of a set of f u e l cost share eguations, and a t o t a l expenditure eguation. The main non-thermal demand equations have the quantities of losses and adjustments and of energy supply use taken out of the data. These data were extracted because i t i s believed that they do not represent components of f i n a l energy demand, but instead represent components of intermediate demand. Even though these guantities are subtracted from the main demand guantities, they must be estimated i n order to determine the desired supply. The losses component i s estimated as a simple proportion of sales or, in the case of the producing regions, as a proportion of production. The re s u l t s of the estimation procedure for energy supply use and losses are reported i n appendix 3.D. The l i s t of the variables and c o e f f i c i e n t s used i n the losses sector are reported i n appendix 1.D; and the actual simulation equations are reported in appendix 2.D. Dsing Table 1, Table 2 and Table 3 in appendix 3.D, one can compare the estimated losses c o e f f i c i e n t s across regions. The proportion of losses to regional demand for crude o i l products 21 in Quebec, Ontario, and the P r a i r i e s i s between .08 and .1; whereas in the A t l a n t i c and B.C. i t i s approximately .05. The smaller proportion in the A t l a n t i c r e f l e c t s the lower amount of pipeline losses. The simple proportion eguation does not f i t the B.C. data very well, and by comparison with the other regions, I f e e l that the estimated c o e f f i c i e n t i s probably too low. The estimated parameters representing the proportion of losses to demand for e l e c t r i c i t y are approximately ,09 in the A t l a n t i c , Quebec and Ontario regions, s l i g h t l y higher at .14 in the P r a i r i e s region, and s l i g h t l y lower at .08 i n B.C. The estimated parameters representing the proportion cf losses to demand, or losses to production in producing regions, of natural gas vary considerably across regions. In the Quebec region the c o e f f i c i e n t i s actually negative because for some reason the losses and adjustment data have consistently been negative and larger i n absolute value than the energy supply use data. In Ontario the proportion i s approximately .06 representing mostly pipeline losses. Since energy supply usage of natural gas i s rather large in a producing region, the proportion i s .17 i n the P r a i r i e s and .28 in B.C. It i s not clear to me why the c o e f f i c i e n t should be so d i f f e r e n t for the two producing regions. The guantities of crude o i l that are imported into the A t l a n t i c and Quebec regions for re-export as petroleum products are not included in the data for domestic demand. These imports were only included in the eguation used to predict the subsidy payments for imported crude o i l (GFSUBO). I did not include the refined products in the export eguation (OILEXPT) nor the crude 22 o i l i n the import eguation (OILIMPT) because r e f i n e d products are not int r o d u c e d anywhere i n the model. In r e t r o s p e c t , I b e l i e v e t h a t I should have l e f t the r e - e x p o r t s out of the subsi d y eguation because the export tax on r e f i n e d products, i s probably set t o cover any subsidy payment on the imported crude o i l . The f a c t t h a t almost no n a t u r a l gas i s used i n the A t l a n t i c r e g i o n i m p l i e s t h a t the s u b s t i t u t i o n p o s s i b i l i t i e s must be estimated s e p a r a t e l y f o r t h i s r e g i o n . S i m i l a r r e g i o n a l d i f f e r e n c e s i n f u e l usage f o r thermal e l e c t r i c i t y g e n e r a t i o n have l e d to the assumption t h a t o n l y c o a l and crude o i l products are s u b s t i t u t a b l e i n the A t l a n t i c and Quebec r e g i o n s , only n a t u r a l gas and crude o i l products are s u b s t i t u t a b l e i n the B.C. S Yukon r e g i o n , whereas i n O n t a r i o and the P r a i r i e s n a t u r a l gas, crude o i l products and c o a l are a l l p o t e n t i a l s u b s t i t u t e s . For gr e a t e r e f f i c i e n c y o f e s t i m a t i o n , the p r o p o r t i o n a t e e f f e c t s of changes i n r e l a t i v e p r i c e s are c o n s t r a i n e d to be the same i n each r e g i o n . The p r i c e s themselves, of course, are d i f f e r e n t i n each r e g i o n , p r i m a r i l y because of t r a n s p o r t c o s t s . Other r e g i o n a l d i f f e r e n c e s i n demand are captured by using a r e g i o n a l s h i f t f a c t o r . Since energy usage i s u s u a l l y a s s o c i a t e d with the u t i l i z a t i o n of some form of c a p i t a l stock, one would expect the adjustment of both t o t a l energy consumption and s h i f t s among f u e l s to take some time. The energy f u e l p r i c e s used i n the c o s t share eguations are expected p r i c e s , not c u r r e n t p r i c e s . Each expected p r i c e i s a moving weighted average o f the c u r r e n t p r i c e and p r i c e s of the p r e v i o u s t h r e e years. The eguation which 2 3 e s t i m a t e s the t o t a l constant (1961 d o l l a r ) energy expenditure i s a l o g l i n e a r f u n c t i o n of both r e a l (1961 d o l l a r ) gross n a t i o n a l expenditure and a 4-year weighted average r e l a t i v e p r i c e term, 7 The r e l a t i v e p r i c e term has a current-weighted composite energy p r i c e (Paasche index) r e l a t i v e to the p r i c e d e f l a t o r f o r gross n a t i o n a l expenditure. Since n a t u r a l gas has not always been a v a i l a b l e i n every market area due to a l a c k of p i p e l i n e f a c i l i t i e s , i t i s d e s i r a b l e t o have a v a r i a b l e t o r e p r e s e n t the s h i f t t o n a t u r a l gas once i t becomes a v a i l a b l e . For t h i s reason each r e g i o n a l set of share eguations has a v a r i a b l e which r e p r e s e n t s the miles of n a t u r a l gas d i s t r i b u t i o n p i p e l i n e . The submodel which e x p l a i n s the f u e l s used to generate thermal e l e c t r i c i t y i s s l i g h t l y d i f f e r e n t from the model d e s c r i b e d above. The eguation used to p r e d i c t the t o t a l c u r r e n t d o l l a r expenditure on f u e l s has no r e l a t i v e p r i c e term and uses the t o t a l c u r r e n t d o l l a r expenditure on thermal e l e c t r i c i t y as the a c t i v i t y v a r i a b l e . The g u a n t i t y of thermal e l e c t r i c i t y demanded i s assumed to be determined as a r e s i d u a l : t o t a l e l e c t r i c i t y demand, determined i n the main demand system, i s s a t i s f i e d f i r s t by an exogenous supply of hydro and nuclear generated e l e c t r i c i t y , and then by the endogenous thermal generated e l e c t r i c i t y . The share eguations use c u r r e n t p r i c e s o n l y , which r e f l e c t s the f a c t t h a t some u t i l i t i e s have the 7 I experimented with a production framework that i n c l u d e d c a p i t a l and labour but r e j e c t e d i t i n favour of the r a t h e r simple f u n c t i o n d e s c r i b e d above because i t provided a b e t t e r f i t over the h i s t o r i c a l p e r i o d . The choice was a l s o i n f l u e n c e d by the f a c t t h a t the v a r i a b l e s i n the simple f u n c t i o n were r e l a t i v e l y easy to f o r e c a s t . 24 capacity to switch quickly between o i l and gas f i r e d generators. The conversion'factor from input Btu to output Btu i s the factor for the i n d u s t r i a l sector only, rather than an average factor calculated over a l l end-use sectors. The system of demand eguations i s f l e x i b l e enough to permit d i f f e r e n t substitution p o s s i b i l i t i e s between each pair of f u e l s , with a corresponding complexity of r e s u l t s , Useful s t a t i s t i c s which summarize the response c h a r a c t e r i s t i c s of the demand eguations are the price e l a s t i c i t i e s (both cwn and cross) of demand. Since the price e l a s t i c i t i e s are a function of the cost share, they need not be constant over the estimation period. However, in the re s u l t s which are reported in appendix 3,B, most of the price e l a s t i c i t i e s are r e l a t i v e l y stable over the estimation period. In a l l of the main (non-thermal e l e c t r i c ) demand eguations the own price e l a s t i c i t i e s f or each region are negative, between 0 and -1; while the cross price e l a s t i c i t i e s for each region are a l l positive, between 0 and +1. In a l l of the a u x i l i a r y (thermal e l e c t r i c ) demand eguations the own price e l a s t i c i t i e s for each region are negative, usually between 0 and -1; while the cross e l a s t i c i t i e s for each region are a l l po s i t i v e , usually between 0 and +1. The s t a t i s t i c a l f i t of each of the estimated eguations and the parameters within the equations are quite good for the t o t a l expenditure equation and the main (non-thermal) demand system; but not quite as good for the a u x i l i a r y (thermal) demand system. As part of appendix 3.B, graphs are presented which indicate t o t a l energy expenditure, the actual and estimated f u e l expenditure shares, the cwn and cross Allen p a r t i a l e l a s t i c i t i e s 2 5 of demand for each region over the h i s t o r i c a l estimation period. More s p e c i f i c comments about the graphs w i l l follow: f i r s t about those i n the non-thermal sectors, and then about those i n the thermal sector. The following comments refer to the graphs which portray the estimation of the main non-thermal demand system. The current dollar expenditure on primary energy f u e l s in the A t l a n t i c region began to r i s e very sharply after 1969. This occured because simultaneously the share and price of o i l rose, and the share of e l e c t r i c i t y f e l l as i t s price remained constant. This awkward state of a f f a i r s was one reason that led me to estimate the A t l a n t i c region separately i n both the share system and t o t a l expenditure system. In fact, only by imposing some c o e f f i c i e n t values i n the Atlantic share system could I obtain sensible e l a s t i c i t y estimates. The own and cross demand e l a s t i c i t y estimates in Quebec, Ontario, P r a i r i e s and B.C. are f a i r l y s i m i l a r because the price c o e f f i c i e n t s i n the share system were constrained to be the same. The c o e f f i c i e n t s were constrained to be egual across regions because the estimation data were pooled across the regions to increase the number of observations. The variation i n the own and cross demand price e l a s t i c i t i e s across regions i s due to regional differences in the fuel expenditure shares. Some of the regional differences i n expenditure shares are captured by including a regional s h i f t parameter in the estimation eguations. S i m i l a r l y , the c o e f f i c i e n t s of the t o t a l expenditure equation are constrained to be the same across regions (except the A t l a n t i c ) , with some cf the regional differences being 26 captured by a r e g i o n a l s h i f t parameter. In both systems, r e g i o n a l d i f f e r e n c e s are a l s o e x p l a i n e d by d i f f e r e n c e s i n p r i c e s . U n f o r t u n a t e l y , i n the t o t a l expenditure system, r e g i o n a l d i f f e r e n c e s are not captured due to v a r i a t i o n s i n the r e a l gross p r o v i n c i a l expenditure because no data were a v a i l a b l e , Instead the n a t i o n a l r e a l GNE data were used f o r a l l r e g i o n s . Comparing the r e g i o n a l c u r r e n t d o l l a r e x p e n d i t u r e s , one notes t h a t the A t l a n t i c expenditure i s s l i g h t l y s m a l l e r than the approximately egual B.C. and P r a i r i e e x p e n d i t u r e , and the expenditure i n a l l t h r e e r e g i o n s i s approximately one-half of the expenditure i n O n t a r i o or Quebec. Comparing the r e g i o n a l primary energy expenditure s h a r e s , one notes that on average, i n the A t l a n t i c 501 of the share i s o i l and 50% i s e l e c t r i c i t y ; i n Quebec 50% of the share i s o i l , about 4$ i s n a t u r a l gas, and 46% i s e l e c t r i c i t y ; i n O n t a r i o about 35% of the share i s o i l , about 20% i s n a t u r a l gas, and 451 i s e l e c t r i c i t y : ; i n the P r a i r i e s about 45% of the share i s o i l , about 15% i s n a t u r a l gas, and 40$ i s e l e c t r i c i t y ; and i n B.C. about 30% of the share i s o i l , about 51 i s n a t u r a l gas, and 65% i s e l e c t r i c i t y . The expenditure shares guoted above are a f u n c t i o n of the r e l a t i v e energy p r i c e s . Therefore the expenditure shares do not i n d i c a t e the f u e l g u a n t i t y shares, measured i n a common Btu u n i t . The f o l l o w i n g comments r e f e r t o the graphs which v i s u a l i z e some of the parameters of the thermal demand system. In \ examining the t o t a l expenditure on primary f u e l s and the a c t u a l f u e l expenditure shares i n each r e g i o n , one i s struck by the wide v a r i a t i o n over the h i s t o r i c a l p e riod. For i n s t a n c e , over the 1960-1973 p e r i o d , i n the A t l a n t i c r e g i o n the expenditure 27 share of o i l e r r a t i c a l l y rose from 30% to 75%; in Quebec the expenditure share of o i l rose in an i r r e g u l a r fashion from 70% to 100%; i n Ontario the expenditure share of coal increased from 85% to 95% and then f e l l to 75%; in the P r a i r i e s the expenditure share of coal rose in an e r r a t i c manner from 50$ to 7555; and in B.C. the expenditure share of o i l f e l l from 80% to 55%, then rose to 8 5%, and f i n a l l y f e l l to 55%. Also i t becomes guite clear when examining the actual and estimated shares that the estimated eguations do not f i t too well. Part of the problem may stem from the fact that most of the parameter estimates are constrained to be equal across the regions that have s i m i l a r f u e l usage: i . e . coal and o i l in Atlantic and Quebec; coal, o i l and natural gas in Ontario and P r a i r i e s ; and o i l and natural gas i n B.C. However, differences in p r o v i n c i a l l e g i s l a t i o n with regard to the sulfur content of coal burned may account for some of the variation in coal usage across regions which i s not captured by r e l a t i v e prices. In examining the own and cross demand e l a s t i c i t i e s of fuels used for thermal generation of e l e c t r i c i t y one notes that In Quebec the e l a s t i c i t i e s involving the guantity of coal are vary e r r a t i c after 1966 because the actual share of coal i s zero for a majority of the observations; i n Ontario the own e l a s t i c i t y of natural gas and o i l are very e l a s t i c and the cross e l a s t i c i t i e s of o i l and natural gas with respect to coal are large; whereas i n the P r a i r i e s i t i s only the own o i l e l a s t i c i t y which i s e l a s t i c and the cross e l a s t i c i t y of o i l with respect to coal which i s large, I suppose the high e l a s t i c i t y of the demand for o i l and natural gas compared with coal r e f l e c t s the marginal 28 nature of using o i l and natural gas in Ontario or o i l i n P r a i r i e s to generate e l e c t r i c i t y . In order to obtain economically sensible e l a s t i c i t y estimates during the estimation of the share system i n B.C. I imposed unitary Allen e l a s t i c i t i e s of substitution between f u e l s . Hence the own and cross price e l a s t i c i t i e s are d i r e c t l y related to the actual f u e l shares. The system of demand eguations has been coded into a simulation model as a separate sector of the integrated model. A l i s t of the endogenous and exogenous variables and c o e f f i c i e n t s used in the demand sector are reported in appendix 1.A; and a l i s t of the actual simulation eguations are reported in appendix 2. A. In order to have the estimated eguations represent.the actual h i s t o r i c a l values during simulation, the residuals of the estimation prodedure are added back. These 'add fa c t o r s ' are also included i n a l l the estimated eguations for 1974-1976, for which preliminary or estimated data are available. It i s assumed that the l a s t add factor that i s necessary to tune the estimated values to the preliminary data i s used for the rest of the simulation period. The 'add fa c t o r s ' are l i s t e d as part of the model eguations i n appendix 2.A. 29 2.4 The Techniques Used During Estimation The expenditure share eguations and parameter r e s t r i c t i o n s which res u l t from the i n d i r e c t translog cost function are detailed in appendix 3.A. To each eguation in the share system an additive stochastic disturbance term i s appended to r e f l e c t errors i n cost minimization. The system of expenditure share eguations has cross-equation r e s t r i c t i o n s imposed during estimation. Hence the system i s estimated simultaneously. Since the sum of the expenditure shares must always be equal to unity, the sum of the disturbance terms for these eguations must sum to zero at every observation. Therefore the variance-covariance matrix of the disturbances i s singular, and cannot be inverted. However, when one of the expenditure share eguations i s dropped, the i t e r a t i v e Zellner method of estimation can be used. It should be noted that the parameter estimates are independent of which eguation i s dropped. The Zellner method w i l l estimate a system of eguations i n which there exists a contemporaneous cor r e l a t i o n in the disturbances between eguations. The i t e r a t i v e Zellner method involves using successive approximations to the variance-covariance matrix u n t i l the generalized least sguares parameter estimates converge to within a preset tolerance l e v e l . The i n i t i a l elements in the variance-covariance matrix are calculated using the single equation residuals with a r b i t r a r y i n i t i a l parameter values. The estimate of the variance-covariance matrix i s used to form the generalized least squares estimator, which i s then used to generate the residuals, and then elements of successive 30 variance-covariance matrices u n t i l convergence i s reached. The i t e r a t i v e Zellner method i s equivalent to maximum l i k e l i h o o d . During the formation of the translcg cost share eguations there have been two types of modifications which a f f e c t the duality between cost and production. The variable used to represent the miles of d i s t r i b u t i o n pipeline miles was added to the expenditure share eguations to explain the s h i f t i n f u e l shares once natural gas had penetrated new market areas. Weighted prices are used in the non-thermal f u e l expenditure share eguations tc capture an adjustment process in which shares respond instanteously to the expected weighted prices, but respond with a lag to current p r i c e s . 8 The more common lagged adjustment model was not used because i t leads to estimation equations which are non-linear i n the parameters. The actual values for the weiqhts were not estimated, but chosen from a number of possible combinations that were examined. 9 Despite the fa c t that these two modifications s p o i l the t h e o r e t i c a l foundation for the translog, I "felt that they were necessary to explain the demand for energy. During the process of estimating the demand systems, a To assess the impact of using weighted prices i n the non-thermal f u e l expenditure share eguations, the parameter estimates from t h i s system using weighted prices were compared to parameter estimates from a system using current prices. The parameters did not d i f f e r by very much between the estimations, probably because there has been r e l a t i v e l y l i t t l e price movement over the estimation period. However, the parametric f i t i n the t o t a l energy expenditure eguation was better with the weighted prices. 9 I did attempt to estimate the weights using an adaptive expectations model, but the non-linear model f a i l e d to converge. 31 certain parameter r e s t r i c t i o n s were imposed. In the main non-thermal system for the At l a n t i c region, the value f o r the c o e f f i c i e n t boo i s imposed because t h i s was the only way I could obtain sensible e l a s t i c i t y r e s u l t s , as explained in the l a s t section. In the main non-thermal demand system for the other regions the value for the c o e f f i c i e n t bgg i s imposed at zero because when freel y estimated i t was so close to zero that the i t e r a t i v e Zellner method f a i l e d tc converge; the value for the c o e f f i c i e n t bgo i s imposed at zero because when freely estimated i t was s l i g h t l y negative and implied complementarity between o i l and gas; and the value for the c o e f f i c i e n t c l i s imposed at zero because the freel y estimated value was i n s i g n i f i c a n t and pos i t i v e , contrary to expectations. In the thermal demand system for the B.C. region the value for the c o e f f i c i e n t boo i s imposed at zero*° because the freel y estimated c o e f f i c i e n t did not yi e l d sensible e l a s t i c i t y estimates, as explained i n the l a s t section. The previous section contained a general description of the in-sample f i t t i n g errors for the demand systems. Another useful measure of the r e l i a b i l i t y of econometric eguations i s the out-of-sample f i t t i n g errors. To provide a guantitative measure of the out-of-sample f i t t i n g e r r ors, the 'add factors' for 1974 onward have been set equal to zero, and a l l exogenous variables l e f t unchanged. Then I compare the 1974 and 1975 estimated energy aggregates with the preliminary actual data available. Only the energy aggregates for energy expenditure, energy 1 0 By imposing a value of zero for the c o e f f i c i e n t boo, t h i s makes the factor demand eguation eguivalent to that which would be derived from the Cobb-Douglas production function. 32 demand, o i l , gas and e l e c t r i c i t y demand are reported because the regional data are much more d i f f i c u l t to obtain in preliminary form. The aggregate demand for coal i s not mentioned because preliminary data were unavailable. A l l of the 1974 and 1975 out-of-sample f i t t i n g errors are reported below as a percentage of the preliminary actual values. The estimated t o t a l current d o l l a r expenditure by Canadians on non-thermal energy fuels (TOT$) i s too low by 10.5% in 1974 and 12.91 in 1975 r e l a t i v e to the preliminary actual values. The estimated t o t a l Canadian demand for primary energy (OBTU) i s too low by 12,91 in 1974 and 15.1% i n 1975. The estimated t o t a l expenditure variable TOT$ does not decline, in percentage terms, as much as the estimated t o t a l primary energy demand OBTU because the fuel prices remain unaltered and only the guantities change between experiments. The percentage change, r e l a t i v e to the preliminary actual values, for the ind i v i d u a l f u e l s are as follows: the estimated Canadian demand for crude o i l (QOIL) i s too low by 21.7% in 1974 and 23.31 i n 1975; the estimated Canadian demand for natural gas (QG AS) i s too low by 19,71 in 1974 and 22.4% i n 1975; and the estimated Canadian demand for e l e c t r i c i t y (QELEC) i s too high by 8.71 in 1974 and 5.81 in 1975. In general, when comparing the percentage changes one notes that the demand for o i l and natural gas are lower than the ov e r a l l primary energy demand, and the demand for e l e c t r i c i t y i s act u a l l y higher. If the percentage error in QOIL i s broken down into erorrs in QOILEA ST and Q0IL8EST, then one finds that the errors in CCILEAST are approximately twice as large as in QOILWEST, 33 It i s not possible to report very accurate out-of-sample f i t t i n g errors for 1976 because a l l of the data are not yet available. When adjusting the add factors to be used i n the solution for 1976, I was aiming at approximately a 4% growth rate, as some National Energy Board and Department of Energy Mines and Resources forecasts were predicting. It now seems possible, according to the l a t e s t 1976 estimates reported i n O i l week, that domestic demand for crude o i l w i l l r i s e at only 1.2% (p. 29, Oilweek, February 14,1977), and that domestic demand for natural gas w i l l r i s e at only 0.1% (p. 37, Oilweek, February 14,1977). The demand system, using no add factors after 1973, predicts that the percentage change i n demand, of 1976 over 1975, for t o t a l primary energy (OBTU) i s a 0.84% increase, for crude o i l (QOIL) i s an increase of 3.3%, and for natural gas i s a decline of 1.1%. In general, when comparing the year over year changes in the errors one notes that the demand system does not predict too well during 1974, but does predict better i n 1975 and 1976. The r e s u l t i n g errors for 197 4 and 19 75 can be summarized in the following t a b l s . For the sake of comparison the errors for the l a s t year of estimation (1973) are given. Year TOTS OBTU QOIL QGAS QELEC 1973 1974 1975 -2.9% -10.5% -12.9% -2. 8% -12.9% -15. 1% -7.9% -21. 7% -23.3% -0.7% -19.7% -22.4% + 3.5% + 8.7% + 5.8% year QOILWEST QOILEAST 1973 1974 1975 -2. 1% -13.9% -16. 1% -13.8% -29.6% -30.9% 3 4 2.5 The Forecast Results Using the Demand Model In order to produce a forecast of energy demands i t i s necessary to specify the future values of only the exogenous variables. These future exogenous variables have been obtained from numerous sources. A detailed description of the assumptions used to produce the base case forecast i s contained in appendix 5.A; and the results of the base case forecast are contained in appendix 5.B. A summary of the growth rates of the major exogenous variables i s as follows: the annual rate of growth for r e a l gross national expenditure (UGNE) i s 5.41 to 1981, then 4.5%; the annual rate of growth of the i m p l i c i t gross national expenditure price index (PGNE) i s 10% i n 1975, 8% i n 1976, 6% i n 1977 and 4% thereafter. The landed price of offshore crude o i l i s estimated to be $13/.b'b.l in 1976, and to increase thereafter at the general rate of i n f l a t i o n . In the current simulations, the Canadian and world price levels are assumed to march more or l e s s in step, and the exchange rate to remain constant at $1 Canadian per $1 OS. The model i s set up, however, so that any induced change i n the exchange rate (for example, due to soma change in energy trade policy) immediately causes a corresponding change in the landed Canadian price of offshore crude o i l . It i s further assumed that a l l Canadian energy prices increase in r e a l terms u n t i l 1980: the crude o i l price i s based on the assumption that i t w i l l reach the world l e v e l by 1980; and the natural gas price i s based on the assumption that a Btu equivalence w i l l be reached with crude o i l in Toronto by 19 81. The average assumed price increase of e l e c t r i c i t y i s 20% per 35 year from 1974 to 1976, then 15% per year to 1980. A l l energy prices r i s e at the underlying rate of i n f l a t i o n (4%) afte r 1981. The average annual growth of hydro and nuclear generated e l e c t r i c i t y supply i s between 2%-4%. The annual growth of natural gas d i s t r i b u t i o n pipeline miles i s 3%-4% for Ontario, P r a i r i e s , and B.C., and 8% for Quebec, Figures 1 to 3 indicate the main features of our energy demand forecasts based on the assumptions outlined above. Figure 1 shows the t o t a l ' projected demand for primary energy i n Canada, with the difference between the numbered l i n e s showing the s p l i t of national demand among the f i v e consuming regions. Figure 2 shows the projected shares of the four primary energy sources i n providing for the t o t a l demand. The fact that the shares do not s h i f t much i s consistent with the fact that the r e l a t i v e prices do not s h i f t very much - especially after 1981. These shares r e f l e c t demand rather than supply, and thus exclude energy production exported and include a l l energy imported for domestic use. Given the price assumptions mentioned above and the projected energy demand outlined in Figure 1, one can vi s u a l i z e the r e s u l t i n g current d o l l a r energy expenditure in Figure 3. 36 2.6 A Comparison cf my Demand Forecast with Others In t h i s section I w i l l compare the r e s u l t s of my demand forecast with the re s u l t s of recent forecasts published by the National Energy Board [34,35,36], the Department of Energy Mines and Resources [31,32], and Corbet [63]. Although attention w i l l be mainly focussed on the latest Department of Energy Mines and Resources report [32] and the l a t e s t National Energy Board report on crude o i l [36] and the l a t e s t National Energy Board report on natural gas [35], brief mention w i l l be given to some e a r l i e r forecasts by the Department of Energy Mines and Resources [31], the National Energy Board [34], and Gorbet [63]. The 1973 Department of Energy Mines and Resources report, An Energy Policy for Canada^ Phase J, contains a standard forecast for energy demand [31, Volume I-chapter 3, Volume IT-chapter 1 ]. The framework underlying the demand forecast i s as follows: The standard forecast i s e s s e n t i a l l y a sector forecast. Forecasts for each sector were made separately, based cn the relationships cf energy use to obvious parameters,... Although the forecasts made in the sectors were i n general based on the same population forecasts, no attempt was made to relate energy consumption to o v e r a l l economic growth.... Since the forecasts are made i n d i v i d u a l l y , the projections of the various sectors could be inconsistent from a general economic point of view [31, Volume I I , page 6]. In view of the above s e l f - c r i t i c i s m and the fact that the •obvious parameters' did not include r e l a t i v e prices, I w i l l concentrate below cn the forecasts from the l a t e s t Department of' Energy Mines and Resources report [32] which has corrected some of these drawbacks. In 1974 the National Energy Board released a report [34] 37 dealing with the exportation of crude o i l . The section of the report which commented on crude o i l demand forecasts that crude o i l and equivalent " w i l l grow at an average annual rate of 3.2% during the next 20 years" [34, p 3-5], although no mention was made of how the growth rate was determined, a l i s t was provided to indicate some possible influences on the trend. The l i s t included conservation, change i n the market areas served, development of new energy intensive industry eguipment, and a v a i l a b i l i t y of competitive f u e l s . No s p e c i f i c mention was made of the influence of the underlying economic growth and r e l a t i v e prices, although the l a t t e r e f f e c t could come under the broad heading of 'conservation'. Instead of comparing my results with t h i s 1974 report, I w i l l compare them below with the l a t e s t National Energy Board report on crude o i l reguirements. The study by Gorbet [63] sets forth the methodology and estimation framework used to generate the r e s u l t s reported in A n-Snercj.y. Strategy for Canada: P o l i c i e s for Self-Reliance [32], The energy price assumptions and underlying macro assumptions are not d i r e c t l y comparable with my model: Gorbet assumes an adjustment toward a r e a l crude o i l wellhead price of $9.00/bbl in 1974 d o l l a r s by 1978, whereas I assume an adjustment towards a r e a l crude o i l wellhead price of $10.25/bbl in 1974 d o l l a r s by 1980; the growth of r e a l GNE that I assume f a l l s between the case fl and case B assumptions made by Gorbet. The re s u l t s i n table 4 are d i f f i c u l t to compare with my results because Gorbet converts the t o t a l primary energy demand into input Btu, but does not give an h i s t o r i c a l value so that I can coordinate the r e s u l t s . Since the Department of Energy Mines and Resources 38 study [32] has u t i l i z e d mere recent data, and has l i s t e d values from the l a s t h i s t o r i c a l period (1975) I w i l l use i t as a basis fo r comparison. The re s u l t s reported i n An Enex<LY, Str.ate.gy_ for Canada,: P o l i c i e s for Self-Reliance [32] are associated with a combination of two alternative energy price assumptions and two alte r n a t i v e economic a c t i v i t y assumptions. The energy price assumptions i n my model closely p a r a l l e l the 'high price' Department of Energy Mines and Resources scenario which assumes the following: O i l prices increase r e l a t i v e l y faster than the prices of other goods and services u n t i l about 1978, when they reach a l e v e l that i s roughly eguivalent to the current international price (about $13.00 per barrel landed in Montreal i n 1975 d o l l a r s ) . Prices f o r e l e c t r i c i t y and coal are assumed to increase at the same rate as o i l prices, and the price of natural gas i s again assumed to adjust to 'commodity-eguivalent* value with crude o i l ($2.25/Mcf at the Toronto city-gate, i n 1S75 dollars) by the l a t e 1970»s. After 1978, a l l energy prices are assumed to increase at only the general rate of i n f l a t i o n . [32, p.49] The forecast assumptions i n my model are very s i m i l a r , with the major exception that a l l energy prices rise i n real terms u n t i l 1980 - or 1981 i n the case of natural gas. Also I have assumed that the international price of crude o i l i s $13.00/bbl in 1976, leading to a commodity-eguivalent Toronto city-gate price of $2.20/Mcf i n 1976 d o l l a r s . The growth rate of r e a l GNE used i n my model f a l l s between the high and lew Department of Energy Mines and Resources assumption. I have used the Department of Energy Mines and Resources average annual growth rate from 1976-1980, but for the post-1980 period I have used the National Energy Board assumption [36, p.33 and 35, p.13-14], The 1974 National Energy 39 Board report [34] on the exportation of o i l did not outline any s p e c i f i c assumption about the underlying growth of the Canadian economy. If I adjust the model variable which represents the t o t a l Canadian demand for primary energy (OBTU) so that i t i s consistent with the Department of Energy Mines and Resources 1975 estimate [32, p. 51] then I can compare the r e s u l t s . The model-generated r e s u l t for OBTU appears i n output Btu's whereas the Department of Energy Mines and Resources result appears in input Btu's. The adjustment factor w i l l therefore represent an aggregate input to output Btu conversion factor. This adjustment factor w i l l be used each year a comparison i s made, thus i t i s i m p l i c i t l y assumed that within the control solution the f u e l shares do not s h i f t very much (see Figure 2), The adjusted simulation value for OBTO i n 1990 i s only 3.2% smaller than the average of the high and low a c t i v i t y values for the Department of Energy Mines and Resources high price scenario [32, p. 51], But the adjusted simulation value for OBTU in 1980 was 9.6% lower, and i n 1985 was 7.2% lower. The projections of primary energy demand from my model are substantially lower in the i n i t i a l years because the r e l a t i v e energy price increases from .1974 to 1980 affe c t the t o t a l demand for energy with a negative price e l a s t i c i t y of approximately -.41 (-.63 for A t l a n t i c ) . After about 1981, when the energy prices remain constant in r e a l terms, the growth in t o t a l primary energy demand i s driven by the gro.wth in rea l GNE. The e l a s t i c i t y of energy demand with respect to r e a l GNE i s 1.C8 (1.12 i n A t l a n t i c ) . Although the Department of Energy Mines and Resources report does not mention 40 the underlying e l a s t i c i t y of energy demand with respect to real GNE, Gorbet mentions that for the two scenarios which use the growth in h i s t o r i c a l economic a c t i v i t y as the basis for the forecast period "the i m p l i c i t e l a s t i c i t y of t o t a l primary energy requirements with respect to GNE i s s l i g h t l y less than unity" [63, p.166], and for the scenario which uses lower future growth rates than i n the h i s t o r i c a l period the income e l a s t i c i t y i s s l i g h t l y greater than unity. It i s not clear from the Department of Energy Mines and Resources re s u l t s exactly what value i s used for the price e l a s t i c i t y of energy demand. But the price response must be f a i r l y weak to permit an average annual growth in primary energy of 4.5% between 1976-1980 for the high-price scenario [32, p. 51], The Department of Energy Mines and Resources report disaggregates the t o t a l demand for energy into the demand for o i l , natural gas, e l e c t r i c i t y , and coal. The numbers used by Department of Energy Mines and Resources for o i l demand Include l i q u e f i e d petroleum gases (IPG), hence the Department of Energy Mines and Resources forecast result w i l l be larger than my model forecast result for o i l . In order to ensure reasonable comparability of the results in 1975, i t i s necessary to estimate the Canadian demand for l i g u e f i e d petroleum gas. 1 1 I f A l The l a t e s t available data are the 1973 and 1974 data for Canadian production of LPG from the CPA S t a t i s t i c a l Yearbook, and the 1973 Canadian consumption (production minus exports) from the S t a t i s t i c s Canada Detailed Energy Su££ly and Demand in Canada. If I assume that the 1975 Canadian production for LEG remains unchanged compared to 1974, as was the case between 1973 and 1974, and use the 1973 r a t i o of Canadian demand to production for the assumed 1975 production then I a r r i v e at a 1975 Canadian demand for IPG of 46.6 Mbbl/d. 41 the assumed 1975 IPG demand of 46.6 Hbbl/d i s added to the 1975 model generated value for crude o i l demand cf 1684.5 Mbbl/d 1 2 then my result i s just 11 lower than the base year Department of Energy Mines and Resources estimated crude o i l demand of 1749 Mbbl/d [32, p.55]. In comparing my forecast results with the Department of Energy Mines and Resources forecast I w i l l add to my model forecast the i m p l i c i t 1975 demand for IPG of 64.5 Mbbl/d, compounded forward by the Department of Energy Mines and Resources average annual growth rate for o i l demand. The model-generated res u l t for crude o i l demand plus the assumed IPG demand i s approximately 111 lower i n 1980 than the average cf the high and low a c t i v i t y values for the Department of Energy Mines and Resources high-price scenario, 8.41 lower in 1985, and v i r t u a l l y eguivalent in 1990 [32, p.55]. When one compares the differences i n the o i l results with the differences in the t o t a l energy demand r e s u l t s , one notes that by implication, I apportion a smaller share to o i l from 1975 to 1985, and then sometime between 19 85 and 1990 I apportion a larger share to o i l . In order to compare my model r e s u l t s with the Department of Energy Mines and Resources r e s u l t s for natural gas demand i t i s necessary to deflate my model f o r e c a s t 1 3 by 31 so that the two res u l t s are i d e n t i c a l for 1975. The adjusted model- generated 1 2 The crude o i l demand value i s derived by adding QQILEAST, QOIIWEST, LOILEAST and LCILWEST and then dividing by .365 to convert milicns of barrels to thousands of barrel per day. 1 3 The .natural gas demand value i s derived by adding QGAS and .345* LOSSGAS. 42 re s u l t for natural gas demand i s approximately 10.2% lower in 1980 than the average of the high and low a c t i v i t y values for the Department of Energy Mines and Resources high-price scenario, 7.2% lower i n 1985, and 5.3% lower in 1990 [32, p.56]. When one compares the difference in the natural gas res u l t s with the difference i n the t o t a l energy demand, one notes that roughly the same natural gas share i s used in both results from 1975 to 1985, and then sometime between 1985 and 1990 my model forecasts a s l i g h t l y smaller share than the EMR model. I w i l l now compare my re s u l t s for e l e c t r i c i t y demand with the Department of Energy Mines and Resources r e s u l t s . I do not have a printout variable for my e l e c t r i c i t y energy supply use and losses. During the h i s t o r i c a l estimation period the average r a t i o of the e l e c t r i c i t y energy supply use and losses over e l e c t r i c i t y demand was about .10. When this r a t i o i s used to calculate the t o t a l e l e c t r i c i t y demand 1 4 i n 1975 one arrives af exactly the same re s u l t as the Department of Energy Mines and Resources estimate. But the model- generated result for e l e c t r i c i t y demand i s approximately 20.3% lower in 1980 than the average of the high and low a c t i v i t y values for the Department of Energy Mines and Resources high-price scenario, 20.5% lower i n 1985, and 20.7% lower in 1990 [32, p.58.]. When one compares the difference i n the e l e c t r i c i t y demand results with the difference in the t o t a l energy demand, one notes that the share of e l e c t r i c i t y derived i n my model i s substantially below the share derived i n the Department of Energy Mines and Resources i * The e l e c t r i c i t y demand i s calculated as (1.1*QELEC)/1000. 43 model. For the sake of completeness one notes that the Department of Energy Mines and Resources forecast of the growth i n the i n d u s t r i a l and other demand for coal i s an average annual rate of 4% per year over the 1975-1990 period [32, p.60], Hence the assumed rate of growth of 4% per year for t h i s exogenous category in my model i s comparable, I do not print out the demand for coal, but in order to have the shares adding to 100 % the coal share would have to be higher than the Department cf Energy Mines and Resources share. I w i l l also compare my crude o i l and natural gas forecasts against those published in two separate reports by the National Energy Board [35,36], In comparing t h e i r r e s u l t s to those of the National Energy Board, the Department of Energy Mines and Resources report states the following: The projections for o i l and gas demand presented in Table 4 and 5 d i f f e r from recent, higher, estimates prepared by the National Energy Board, The two sets of estimates are not s t r i c t l y comparable since they have been prepared using dif f e r e n t methods and assumptions. The EMR projections are based on a ' t o t a l energy' framework related to s p e c i f i c assumptions with regard to demographic and economic a c t i v i t y , energy prices, and market shares. The NEB projections were derived from detailed analysis of the domestic o i l and gas markets on the basis of submissions received at public hearings and independent analysis [32, p.57], Although the National Energy Board report Canadian Oil.: SuDj>l_y_ and Requirements [36] s p e c i f i e s some major assumptions with regard to r e a l GNE growth, population growth, and the price of natural gas and crude o i l [36, p.33], i t i s not clear how these assumptions enter the f i n a l demand projections. The National Energy Board demand projections from 1974-1994 are in terms of average annual growth rates: between 2.5% and 3,2% east 44 of the Ottawa Valley depending upon the impact of conservation programs; between 3.61 and 4.31 west of the Ottawa Valley, depending upon the impact of conservation. The National Energy Board forecast for t o t a l Canadian o i l demand, including the effe c t cf conservation, i s an average annual growth rate of 3,11 over the period 1974-1994 [36, p.42-43], which i s v i r t u a l l y i d e n t i c a l to i t s 1974 projection. I w i l l use 1975 as a base year i n which to match the model-generated Canadian demand against the National Energy Board estimate. The model- generated demand for crude o i l in 1975 i s 2.51 higher than the National Energy Board estimate. The model-generated res u l t for Canadian crude o i l demand i s approximately 13.51 lower in 1980 than the National Energy Board forecast, 11.71 lower in 1985, and 3.01 lower in 1990 [36, p. 89]. It i s d i f f i c u l t to compare the National Energy Board forecast and the Department of Energy Mines and Resources forecast because of the in c l u s i o n of LPG demand i n the Department of Energy Mines and Resources projection, but i t appears that the National Energy Board forecast and the average cf the high and low a c t i v i t y values i n the high price Department of Energy Mines and Resources forecast f o r crude o i l are very sim i l a r . As in the National Energy Board o i l report, the National Energy Board report Canadian Natural Gas^ Su££l^ and i ^ S i l l S J S i l i J [35] s p e c i f i e s some major assumptions with regard to r e a l GNE growth and the price of natural gas and crude o i l [35, p.2 and p.12-14] for three scenarios, but the relationship between the assumptions and the demand forecasts i s not c l e a r l y s p e c i f i e d . In each of the National Energy Board's three 45 scenarios i t i s assumed that a Etu price equivalence between crude o i l and natural gas w i l l be established. The major differences i n the assumptions behind the three forecasts are "di f f e r e n t expectations as to the extent that higher energy prices w i l l a f f e c t economic a c t i v i t y , and different assumptions as to how great the e f f o r t to conserve energy w i l l be" [35, p.13]. The National Energy Board continues to argue for the necessity of proposing a range of scenarios because "the assumptions as to the e l a s t i c i t y cf t o t a l energy demand with respect to higher energy prices and the e l a s t i c i t y of the demand for gas with respect to the prices of gas and other fuels are necessarily a matter of judgement since a precise quantitative estimate cannot be r e l i a b l y calculated at t h i s time" [35, p.13]. Although I agree that a wide range of error may occur i n any attempt to forecast e l a s t i c i t i e s , I believe that a precisely s p e c i f i e d r e l a t i o n s h i p i s superior to judgemental assumptions because only with a s p e c i f i c relationship can one continue to make predictions under d i f f e r e n t economic conditions. I w i l l compare my results with scenario I I , the National Energy Board medium forecast, and scenario I I I , the National Energy Board low forecast [35, p.13-14], The medium forecast assumes that higher energy prices reduce economic a c t i v i t y and induce conservation e f f o r t s . The rea l GNP growth after 1980 i s forecast to be 4.5% par annum. The market share of natural gas i s assumed to Increase to 1980 and then gradually decrease. The average annual growth i n natural gas sales in th i s scenario i s 8.5% from 1974-1980, and 3.5% from 1981-1995. The scenario III assumptions are i d e n t i c a l , except that i t i s stated that 46 stringent conservation measures are adopted. The forecast of natural gas sales i s roughly the same for scenario III as for scenario II from 1974-1980. However, the stringent conservation measures reduce the growth in natural gas sales to 3% per annum from 1980 to 1995. Cnce again I match up my 1974 value for natural gas sales with the National Energy Board value to f a c i l i t a t e the comparison of res u l t s . The model- generated value for net natural gas sales (QGAS) i s 1.6% lower than the National Energy Board value. The adjusted model- generated r e s u l t for QGAS i s approximately 9.4% lower in 1975 than the National Energy Board scenario II (medium) forecast, 25,3% lower in 1980, 21,9% lower i n 1985, 14, 8% lower in 1990 and 8.5% lower i n 1995 [36, p. 19 ], The adjusted model- generated r e s u l t for QGAS i s approximately 9.4% lower i n 1975 than the National Energy Board scenario III (low) forecast, 23.4% lower in 1980 16.5% lower in 1985, 7.4% lower in 1990 and .9% higher in 1995. The National Energy Board forecast for 1975 and 1976 i s extremely high, and at odds with the estimate of 1.2% growth in domestic sales for 1975 and forecast of 1.2% growth i n domestic sales for 1976 reported in Oilweek (p.44, February 16, 1976). The lack of price responsiveness i n the National Energy Board forecast i s noted i n an interesting comparison by H e l l i w e l l [81] of the 1969 National Energy Board report on energy supply and demand i n Canada [33], the 1975 National Energy Eoard report on natural gas supply and requirements [35], and a preliminary version of my demand model. In general I can state that my forecast, when compared to the forecasts of the Department of Energy Mines and Resources 47 £32] ana the National Energy Board [35,36], i s substantially lower during the period 1975-1980, and thereafter usually grows at a s l i g h l y higher rate. Most of t h i s discrepancy i s a result of the eguation predicting t o t a l energy demand, This eguation has a substantial negative r e l a t i v e price e l a s t i c i t y and a rather large GNE e l a s t i c i t y . In the approximate comparison of the r e l a t i v e fuel shares between my forecast and the Department of Energy Mines and Resources forecast one notes that i n the i n i t i a l years I apportion a smaller share to o i l and then i n the l a t e r years a larger share, roughly the same share to natural gas in the e a r l i e r years and then a s l i g h t l y lower share in the l a t e r years, a smaller share to e l e c t r i c i t y throughout the period, and probably a higher share to coal. It i s not easy to compare energy shares when examining the National Energy Board r e s u l t s . 48 3. Modelling the Supply of Crude O i l and Natural Gas The relevant economic supply l i t e r a t u r e for the petroleum s e c t o r 1 5 w i l l be described i n four sections. The f i r s t three sections contain comments on three f a i r l y d i s t i n c t i v e aspects of the supply process: production, development, and exploration. The fourth section contains a brief summary of research examining the regulation of crude o i l and natural gas supply. Within each of the f i r s t three sections I w i l l survey the economic studies that relate to the desire to build a supply sector for both Canadian crude o i l and natural gas; and I w i l l also indicate what I would l i k e to-do, i f i t i s different from what was done. The actual supply models for non-frontier crude o i l and natural gas are detailed in the following two chapters, 1 S Occasionally I w i l l f i n d i t convenient to use the term petroleum sector to refer to the sector of the economy which supplies both crude o i l and natural gas. 49 3.1 The Production of Crude O i l and Natural Gas It was reported in the 1 9 7 3 EMR study that a normal production p r o f i l e from a cool exhibits a rather r i g i d skewed pattern. The detailed pattern i s given for a t y p i c a l pool of crude o i l and of natural gas [ 3 1 , Vol.11, p , 8 0 J . For crude o i l the assumption of a fixed pattern i s probably not h i s t o r i c a l l y accurate, mainly due to the excess capacity that existed in the industry. For natural gas the peak rate (rate-of-take) i s set by long-term contracts. This fact leads to a f a i r l y uniform production pattern. The Alberta Energy Resources Conservation Board (AERCB) reports that for natural gas in both the F o o t h i l l s System and the Plains System the constraint on production i s f e l t through pipeline capacity, because the processing plant and adjusted wellhead capacity both have been larger than the pipeline capacity [ 7 , p. 12. 1 3 ] . Even though a fixed extraction pattern i s assumed over the l i f e cf a pool, economic conditions c e r t a i n l y have some influence, as documented by Bradley [ 2 0 ] , Cornelscn [ 4 2 ] and Watkins [ 1 5 4 ] . Bradley [ 2 0 , p . 2 8 ] has emphasized the fact that production from a given pool involves depletion cf a fixed volume, therefore the production pattern should be chosen to maximize the asset value cf the resource. Even so, he assumes a fixed declining production pattern, with the rate of decline being estimated. The i n i t i a l decision to develop a pool involves c a p i t a l expenditure decisions to d r i l l wells (and possibly u t i l i z e enhanced recovery equipment), to build gathering v systems, and to build processing plants (for natural gas only). 50 After the c a p i t a l investment i s i n place the economic decision about the l i f e time of a pool must be made on the marginal unit extracted: production should continue as long as the marginal revenue of each unit extracted i s greater than or egual to the marginal variable cost. Market conditions can e a s i l y a f f e c t the amount of recoverable reserves (ultimate economic recovery) and hence a f f e c t the l i f e of a pool. The production p r o f i l e must be altered i f demand pro-rationing i s imposed. The production pattern can also be altered due to a change i n economic conditions through additional development d r i l l i n g or enhanced recovery. But these procedures are better analysed as decisions about reserve development, discussed in section 3.2. As indicated l a t e r , in sections 4.1 and 5.1, a fixed p r o f i l e has been chosen for the production of crude o i l and natural gas. But the use of a fixed production p r o f i l e e x p l i c i t l y rules cut any effect on the rate of exploitation through the user cost, which has been discussed by Davidson [46,48] and Scott [ 126,127 ]. The user cost can be defined as "the. highest present value of marginal future p r o f i t s given up by producing that barrel of o i l [or unit of natural gas] currently rather than in the future" [48, p.416], Davidson [46] has i d e n t i f i e d three types of user cost associated with the petroleum industry: the user cost inherent in a l l non-renewable materials, the user cost related to ultimate recovery, and the user cost due to the rule of capture. Alberta, which produces about 85% cf the crude o i l i n Canada, has had pro-rationing and u n i t i z a t i o n regulations in e f f e c t (see Crommelin [4 3, p.42-46 ]) to avoid user costs associated with the rule of capture. 51 Regulations in ef f e c t prevent producers from extracting their resource at a rate that i s greater than the maximum e f f i c i e n t rate, hence the user cost associated with ultimate recovery w i l l he zero. ft user cost accompanies the production of any raw material due to the f i n i t e nature cf the resource stock: the more used today, c e t e r i s paribus, the less there w i l l be available tomorrow. Hence under the p r o f i t maximization assumption marginal revenue must cover the marginal user cost plus a l l other marginal costs - including royalty payments. Therefore i f the price i s expected to rise substantially i n the future such that the user cost i s p o s i t i v e 1 6 then current production w i l l tend to be r e s t r i c t e d . On the other hand, the expectation of a decline in price substantial enough to make the user cost negative, w i l l tend to expand current production. The unsubstantiated claim has been made that " i n absence of developed futures markets, producers' subjective expectations of the user costs inherent i n a l l raw materials are major determining factors i n the rate of exploitation of energy resources" [48, p.420]. I plan to ignore the eff e c t of user cost on the fixed production pattern because to model the producers' forward behaviour so that future marginal p r o f i t s can be discounted i s a very d i f f i c u l t task. For the period 1973 to present the natural gas and crude o i l price.s have both risen f a s t e r than the intere s t rate. But producers have also 1 6 The price must be expected to increase r e l a t i v e to production costs at an annual rate greater than the expected rate of in t e r e s t . The converse i s true for negative user costs. 52 experienced r i s i n g costs through increased royalty payments, and increased federal taxation because royalty payments are non-deductible. Even so, there has probably been a positive user cost associated «ith production over the l a s t two years. U n t i l Canadian crude o i l prices are based on a parity with i n t e r n a t i o n a l prices, and u n t i l Canadian natural gas prices are based on a commodity parity with crude o i l prices, the Canadian crude o i l and natural gas prices w i l l probably rise at the wellhead over the next few years. Hence over t h i s period posi t i v e user costs might be expected (depending upon cost increases, of course). 53 3,2 Development of Natural Gas and Crude O i l Resources Once production commences from petroleum reserves, the product Is sold at the market price. Any margin between the unit price and the unit r e a l factor cost for land, labour and c a p i t a l , a l l of which must be paid t h e i r opportunity costs in the next best a l t e r n a t i v e use, i s economic rant which must be divided among governments and the producers. The true economic costs which are relevant for the decision about the supply p r i c e 1 7 do not include r o y a l t i e s , lease payments and certa i n taxes which are a l l means that governments use to c o l l e c t economic rent. But before production occurs development decisions must be made.1 8 A c r u c i a l determinant in the development decision i s the adequate rate of return on c a p i t a l invested i n obtaining the output of the reserve. Development decisions f a l l under the general heading of investment decisions because the nature of petroleum production reguires expenditures to occur at a dif f e r e n t period of time from the output. To calculate the supply price a present value c a l c u l a t i o n must be used to impute a per unit cost that i s necessary to repay the i n i t i a l investment and other factcr-payments for a given output stream. The following formula i s used for the supply p r i c e : 1 9 1 7 The term supply price s h a l l be used to indicate the price necessary to pay a l l factors t h e i r opportunity costs over the l i f e cf the production pattern, 1 8 One of the most comprehensive economic analysis of development decisions has been done by Bradley [20], 1 9 The formulation i s adapted from Eradley [20, p.18], 54 SP= (sum (t=1,T) (I (t)+0P (t) ) / (1+R) **t) / (sum (t= 1 ,T) Y (t) / (1+R) **t) where: SP = supply price, constant $/unit I (t) = investment expenditure in time t, constant $ OP (t) = operating expenditure in time t, constant $ Y (t) = output at time t , u n i t s 2 0 R = r e a l discount rate T = length of output stream. There have not been many studies using Canadian data that calculate the development supply price. A study by Watkins [154] uses the above formulation in order to get a reserve-weighted average development supply price for enhanced recovery projects. An e a r l i e r a r t i c l e by Watkins and Sharp [153] calculates a general supply price for conventional Alberta crude o i l that includes both exploration and development costs. But they are only interested i n calcu l a t i n g a supply price for e x i s t i n g reserves, and hence set to zero exploration costs i n the forecast period. It would be desirable to formulate a per unit development cost function for crude o i l and for natural gas which i s a function of an a c t i v i t y variable such as d r i l l i n g footage or number of wells d r i l l e d . I t would be necessary to r e l a t e the e f f o r t variable both to the amount of reserve additions (through a geological-type model) and to the associated costs. Once the development cost, operating cost and guantity of reserve additions are known i t i s possible to calculate the development supply price. The e f f o r t variable could then be adjusted to close the gap between the discounted expected wellhead price and 2 0 I f the actual output stream d i f f e r s from the expected then the investor w i l l experience c a p i t a l gains or c a p i t a l losses on the development expenditure. 55 the t o t a l supply price plus the unit royalty and rental payments. In examining development decisions about crude o i l reserves, one must consider the p o s s i b i l i t y of either development d r i l l i n g or enhanced recovery. As documented by the Alberta Energy Conservation Board, enhanced recovery schemes seem to be an important element of the supply i n Alberta: as of the end of 1973, 11. 2 Bb'bl of crude o i l are estimated to be recoverable under current technology and price; but only 7.5 Bbbl w i l l be produced by primary extraction, and the other 3.7 Bbbl w i l l be recovered through enhanced recovery operations [7, p.2.78], Without detailed data, of the sort Watkins [154] used, i t would be very d i f f i c u l t to distinguish between reserve appreciation due to development d r i l l i n g or enhanced recovery. Even i f we were able to distinguish between the two types of reserve additions, we would be faced with adjusting the production p r o f i l e in the case of enhanced recovery. A s i m p l i f i e d approach to the problem of adjusting the production pattern would leave the p r o f i l e unaltered, but would include any reserve appreciation or any increase in recoverable reserves (through enhanced recovery or additional d r i l l i n g ) as new reserve additions which are exploited according to the fixed production p r o f i l e . Watkins [154, p.4] indicates a pattern of extraction from enhanced recovery techniques which i s similar to the p r o f i l e described in sections 4.1 and 5.1, But lack of readily available data, and lack of time have prevented me from continuing to work on t h i s aspect of the supply model. The treatment of development supply and costs used 56 i n the diss e r t a t i o n are contained i n Chapter 4 (sections 4.1 and 4.2) and Chapter 5 (sections 5.1 and 5.2). 5 7 3.3 Exploration for Crude O i l and Natural Gas Reserves ' It would be desirable to develop a supply price that w i l l cover the exploration expenditure necessary to discover a unit of petroleum reserve. The exploration function i s perhaps the most d i f f i c u l t to estimate; but i t i s the c r u c i a l element of the long-run supply of output. An attempt must be made to predict not only the forthcoming supply of new discoveries but also the marginal cost of additional discoveries. Given the cost and amount of new discoveries i t i s then possible to calculate a supply price which i s capable of being added to the supply price for the development of reserves. This t o t a l supply price can then be compared to the present value of future expected wellhead prices, with the difference being shared between the government through r o y a l t i e s and rental payments, and the producer through extra p r o f i t s . This sort of framework would allow one to analyse the impact on exploration e f f o r t , and hence cn long-run supply, through a change in the royalty rate or a change in the wellhead p r i c e . If the wellhead price increases, net of any corresponding increase in the royalty, then exploration e f f o r t should increase u n t i l the supply price i s egual to the net wellhead price. Therefore to evaluate the long-run supply one must predict the future wellhead prices and royalty rates, a i t h i n the supply model, I wish to distinguish between exploration for crude o i l and for natural gas. But the geological and geophysical exploration e f f o r t s are probably aimed more toward the discovery of hydrocarbon deposits in 58 general than toward a pa r t i c u l a r type of deposit. Even during the d r i l l i n g stage the type of deposit may not be known beforehand. Therefore, as Watkins [153] points out: "the intention of exploration i s the discovery of hydrocarbon deposits...and i n s t r i c t economic terms, a s p e c i f i c cost of o i l [or gas] does not e x i s t " [153, p.1]. In order to separate the exploration expenses into expenses for crude o i l and f o r natural gas, the j o i n t nature of the exploration cost function must be ignored. To separate the joint costs betweeen crude o i l and natural gas I used an a l l o c a t i v e function discussed generally i n sections 4,2 and 5.2, and s p e c i f i c a l l y in appendix 4.B. There have been few empirical attempts to measure the supply of new discoveries. An economic model for crude o i l discovery i n the United States has been estimated by Erickson [52] and Fisher [55], The Erickson-Fisher model contains three regression eguations which describe new f i e l d wildcats, the success rate and the average size of discovery a l l in terms of pr i c e , geological knowledge and a measure of costs. The model predicts a long-run price e l a s t i c i t y of new crude o i l reserves discovered equal to +0.93 . 2 1 Uhler has c r i t i c i s e d t h e i r approach because "the models are not spec i f i e d to allow s h i f t s i n the supply relationship caused by growing geological knowledge and the exhaustion of remaining reservoirs i n the region" [ 147, p. 22]. Another approach to the long-run supply of United States crude o i l reserves, which focuses on the impact of tax changes, 2 1 The Erickson-Fisher estimate has been guoted in Erickson [52, p.42], and the regression r e s u l t s reported in Burrows and Domencich [27, p. 220-227 ], 59 has been explored by Erickson, Millsaps and Spann [54]. They postulate a desired long-run equilibrium l e v e l of reserves in terms of expected prices, user c o s t , 2 2 and production r e s t r i c t i o n s . The tax incentives enter the o i l supply picture through t h e i r . e f f e c t on the user cost. They postulate a stock adjustment process whereby the actual reserves approach the desired l e v e l . Using United States data they estimate that the long-run price e l a s t i c i t y of reserves i s +1.0; and that the long-run user cost e l a s t i c i t y of reserves i s -0.71. The adjustment c o e f f i c i e n t i s approximately 0.1, indicating that 10% of the gap between desired and actual i s closed each year. Their empirical estimates have emitted a po t e n t i a l l y important variable by assuming that the finding cost i s constant. It i s a valuable contribution to the analysis of tax e f f e c t s on supply, but I f e e l that too much emphasis i s placed on the flow of output without adequate account being taken of the fact that a fixed stock i s being depleted. Using Canadian data there have only been three studies of the exploration process of which I am aware: by Ryan [123,124], Uhler [147] and Eglington [51]. A l l of these studies have focused on Alberta o n l y , 2 3 Ryan presents his postulate that "the rate of crude o i l discovery i s proportional to the accumulated geological knowledge and the amount of undiscovered o i l " [123, 2 2 The term user cost i s used i n the Jorgenson sense of being a measure of the i m p l i c i t price to the firm of c a p i t a l embodied i n o i l reserves. 2 3 At present Alberta has 90% of Canada's recoverable reserves, and 86% of Canada's productive capacity from conventional non-frontier sources of crude o i l [8, p.2, table I I ] ; and 84% of Canada's recoverable reserves of natural gas [8, p.2, table I I I ] , 60 p.219]. He uses a l o g i s t i c function to describe geological knowledge in terms of the number of wells d r i l l e d . He uses a non-linear least sguares f i t t i n g technique to estimate the parameters of his model. He obtains an excellent f i t between the cumulative new f i e l d wildcats and the cumulative i n i t i a l recoverable (and i n i t i a l - i n - p l a c e ) crude o i l reserves. But Ryan has not used any economic variables i n his a n a l y s i s . 2 4 One of the parameters of the Ryan model i s the stock cf ultimate reserves. When he f i t s the model with appreciated reserves the results are that 13-15 Bbbls of ultimate recoverable reserves and 38-42 Bbbls of ultimate o i l - i n - p l a c e reserves exist i n alberta, assuming that no new major plays are found [124, p.242, table 2 and table 3]. The Ryan extimate i s rather low in comparison with the 1973 estimate by the Geological Survey of Canada (GSC) which i s reported in the EMR study [31, Vol.1]. The GSC, using a geological survey of sedimentary basins, indicates 16.3 Bbbls of ultimate recoverable crude o i l . 2 5 Uhler has developed a model which s p e c i f i c a l l y examines both the costs and supply of new reserves through the exploration process. He postulates that the number of new reservoirs discovered "can be treated as a Poisson process and that i t s mean rate (intensity) depends upon the amount of resources allocated to searching e f f o r t " [147, p.75]. The amount 2 4 I t would have been r e l a t i v e l y simple for him to assume a constant cost per well and then derive a function showing the increasing marginal cost per bbl of newly discovered reserves. 2 5 The GSC reports only a t o t a l for Alberta, Saskatchewan and Manitoba (18.3) and northern B.C. (1.6). I assumed that Alberta's share was 90% of the above t o t a l (see a preceeding footnote). 61 of resources allocated w i l l , i n turn, depend strongly on economic factors and on the maturity of the region. The mean rate of discovery i s postulated to be a function of exploratory d r i l l i n g footage/period (measure of effort) and the cumulative exploratory footage/unit area (measure of accumulated knowledge and maturity of a region). I t i s assumed that the sizes of the reservoirs discovered are lognormally d i s t r i b u t e d with respect to cumulative d r i l l i n g footage. Since Uhler never f u l l y u t i l i z e s his stochastic Poisson production function, his most important contribution i s the derivation of a t o t a l and marginal expected cost f u n c t i o n . 2 6 Uhler estimates his model for various regions in Alberta, and uses the results to forecast increases in the cost of finding additional crude o i l and natural gas. Assuming an exploration d r i l l i n g cost of $25 per foot, Uhler finds that i n one region the cost of gas reserve discoveries rises by fourfold over 6 years from $0.038/Mcf in 1972 to $0.132/Kcf in 1977 (with an additional 1.2 Tcf discovered) [147, p. 88']; and in the same region the cost of crude o i l reserve discoveries rises from $.28/bbl to $.72/bbl (with an additional 107 MMbbl discovered) over the same period [147, p.89]. 2 7 Allowing for one standard 2 * His cost curves come from assuming a constant cost per foot of exploration d r i l l i n g . He interprets the marginal cost curves as the relat i o n s h i p between the supply price of reserves-in-place and the expected reserve discoveries in each period. I f the supply price i s calculated on an output basis then a price i s obtained that can be added to the development supply price. His analysis also very neatly explains the marginal cost curve s h i f t i n g over time due to exhaustion. 2 7 A l l reserve estimates reported are i n i t i a l in-place and not i n i t i a l recoverable reserves, because these tend to fluctuate l e s s due to market conditions and recovery technology, Uhler uses recovery factors of .7 for gas and .3 for o i l [147, p. 88-89 ]. 62 deviation on the size of expected discoveries, which i s quite large, s t i l l implies rapidly r i s i n g marginal costs for the area under study. These rapidly r i s i n g marginal cost curves are the result of continual exploratory e f f o r t in regions that are mature. But i t i s not clear i f i t i s appropriate to use the parameters estimated for the region in the Uhler study for other regions that are underexplored. Seme measure of the marginal cost curve that i s associated with additional discoveries from the non-frontier area i s needed i f one i s te calculate the supply pri c e . It would be desirable to be able to relate an e f f o r t variable, such as d r i l l i n g footage or number of wells d r i l l e d , to both the discovery cost and the size of discovery. Then i t would be possible to calculate the marginal cost associated with the discovery of an additional unit of reserves. Neither the •hler nor Ryan studies can be used without extension because the Uhler study covers only part of Alberta's southern basin for crude o i l and natural gas; while the Ryan study covers a l l of Alberta for crude c i l only. It could be possible to use CJhler's parameter estimates in other regions i f the exogenous e f f o r t variable were normalized to the same area size. This type of extrapolation i s c l e a r l y r i s k y because there w i l l be no s t a t i s t i c a l basis upon which to base the i m p l i c i t assumption that the mean rate of discovery and the mean size of discovery w i l l follow the same pattern with cumulative d r i l l i n g footage. The work of Ryan would have to be extended by c a l c u l a t i n g a marginal cost function, by formulating a function that describes 63 the cost per well d r i l l e d , and by developing estimates for natural gas reserve discoveries. To get r e s u l t s for a l l of western Canada the same parameter estimates of the marginal cost function would be imposed for the larger region. Time did not permit me to implement any of these exploration or development functions. Instead, for exploration I have used the National Energy Board estimates for gross reserve additions of both crude o i l and natural gas; and for development I have used the assumption that reserves are developed as needed to meet demand. As explained in sections 4,2 and 5.2, the marginal costs of development and exploration are aggregated together, and made a function of cumulative reserve discoveries. In a way t h i s i s unfortunate because the supply functions used i n the model are not sensitive to price changes. 64 3.4 The Economic Regulation of Crude O i l and Natural Gas Supply This section w i l l end the somewhat lengthy survey of various models describing aspects of the supply of crude o i l and natural gas, The i n i t i a l impact of most government regulations tends to influence the supply side of the. market 2 8 (explained i n Hamilton [69], Kahn [92 ], Mitchell [112], and Ritchie [122]). Government p o l i c i e s are enacted through regulations l i k e the r e s t r i c t i o n of supply through pro-rationing of market demand in the crude o i l industry (documented by Khoury [98] and Lovejoy £101]), the imposition of import guotas on United States crude o i l industry (described in Adelman [3,4], Manes [111], and the United States Task Force report [149]), the creation i n Canada of the National O i l Policy l i n e i n 1961 (Anderson [ 9 ] , Debanne £50], and Hamilton and Schwartz [68]). The tax and royalty structure can•influence the supply through aff e c t i n g the rate of return on investment. Royalty payments are discussed in Gainer and Powrie [61], Hyndman and Bucovetsky [88], and Waverman £159]; and tax concessions to both crude o i l and natural gas producers through the depletion allowance and immediate write-off provisions for most exploration and development expenses are discussed in Bucovetsky [25], Burton [28], Davidson [47], Jenkins [89], and McDonald [105]. 2 8 The demand for crude o i l or natural gas can be affected i n i t i a l l y through direct government manipulation of prices: f o r example, the Federal Power Commission price c e i l i n g imposed on natural gas in the United States, and the price freeze on crude o i l i n Canada since 1973. 65 4. Non-frontier Natural Gas Production The non-frontier natural gas production s e c t o r 2 9 explains the annual production flows; the costs of discovering, developing and producing; the net producer income, taxation payments and royalty payments; the rents accruing to the major participants in natural gas production and consumption; and the accumulation of certain stock variables. H i s t o r i c a l data, obtained from the Canadian Petroleum Association S t a t i s t i c a l Yearbook , have been used from 1947-1974. A l l of the model variables which accumulate over time have been carried forward from simulations which cover the pre-1974 period. A l i s t of the endogenous and exogenous variables and c o e f f i c i e n t s used in the non-frontier natural gas production sector are reported i n appendix 1.B. A l i s t of the actual simulation eguations contained in the natural gas sector are reported i n appendix 2.B. The construction of most of the exogenous data i n the natural gas sector are contained i n appendix 4.A. The construction and sources for the c o e f f i c i e n t s used i n the natural gas sector are contained in appendix 4.E and appendix 4.C. The r e s u l t s of the forecast solution are contained i n appendix 5.B. 2 9 The ncn-frontier natural gas supply model was developed from a model used by Helliwe.ll [75] in his study of the Mackenzie Valley pipeline. 66 4,1 ft Description cf the Production Process The production of non-frontier natural gas i s assumed to conform to a r i g i d skewed pattern reported in An Energy Policy for Canada- Phase _1 [31, Vol. I I , p. 80]. The detailed production p r o f i l e for a t y p i c a l pool of natural gas consists cf production at the peak rate for the f i r s t 15 years, followed by 13 years of production declining at 151 per y e a r . 3 0 The peak rate i s the usual contractual rate of 1 mcf per day for each 7300 mcf of i n i t i a l recoverable pipeline gas reserves (1:7300 r a t i o ) . By using t h i s contractual rate for 15 years (by which time 75% of the ultimate recoverable gas has been produced), followed by almost as many years of declining production, a pattern i s developed which i s s i m i l a r to that used by the Alberta Energy Resources Conservation Board [7, (ERCB 74-18), p. 12-21 ]. The model does allow an alternative production p r o f i l e , for newly hocked-up reserves, which has a f a s t e r recovery rate. A maximum rate of 1:3650 was found by McDaniel [57, Vol II] to increase the present values of production from almost a l l of the s i x t y major Alberta pools examined. The 1:3650 rate i s maintained u n t i l one-third of the i n i t i a l recoverable reserves 3 0 The production pattern has been altered s l i g h t l y from that reported in the EMR study [31] so that by the 29th year of production, 100% of recoverable natural gas w i l l be extracted. This was necessary because even as time approached i n f i n i t y the recoverable reserves were not a l l extracted under the p r o f i l e assumed i n the EMS study. The main a l t e r a t i o n has been to use the more usual ncn-frontier peak rate of 1 Mcf/d for each 7300 Hcf of i n i t i a l recoverable pipeline gas reserves (1:7300 ratio) used in Cornelson [42, p.20] rather than 1:8000 r a t i o used for f r o n t i e r pools i n the EMR study [31]. 67 have been extracted, after which the rate declines by 101 per year. The production l i f e i s 17 years. The McDaniel maximum extraction rate i s approximately the same as the maximum practicable unconstrained pool capacity of 1:4000 reported by the alberta Energy Resources Conservation Board [7, (ERCB 74-18), p. 12-21]. For a l l the main policy simulations the slower 1:7300 rate i s used rather than the 1:3650 rate. The potential for p r o f i t a b l y faster extraction i s therefore l e f t as a safety margin in case demand should grow unexpectedly fast. Production in the current year draws gas from reserves hooked up in each of the preceding 29 years. Since the policy simulation runs t y p i c a l l y start well aft e r the i n i t i a l development of Canadian non-frontier reserves, a variable (GASMax73 for runs st a r t i n g in 1974) i s defined that represents potential future annual production from a l l reserves connected before the simulation begins. As an alternative to the model-generated values f o r the variable GASMAX73 the National Energy Board values for the d e l i v e r a b i l i t y forecast of established reserves from conventional producing areas with no reserve additions [35, p.60] could be used. But there seems to be a discrepancy between the cumulative production that the National Energy Board assumes from the end-1973 reserve base and the size of the end-1973 reserve base. If one assumes a 101 annual rate of production decline after 1995, the l a s t year of published National Energy Board production from previously established reserves, then one discovers that the cumulative production from end-1973 68 established reserves i s approximately 5 0 t c f by the year 2005 [35, p. 60], But the National Energy Board has stated e a r l i e r in i t s report that "The Board's estimate of remaining established reserves, 60.6 t c f , i s based on detailed evaluation of s p e c i f i c pools containing 70 per cent of the reserves in Western Canada together with a more general treatment of the other reserves" [35, p.33]. Although the National Energy Board end-1973 reserve base is approximately H% lower than my model-generated value of 63.2 t c f , the National Energy Board end-1973 reserve base i s approximately 10 t c f greater than the i m p l i c i t end-1973 reserve base obtained from accumulating the production mentioned above. 3 1 Part cf t h i s discrepancy could be explained i f the National Energy Board did not include i n i t s d e l i v e r a b i l i t y forecast the 5 t c f of unconnected and non-producing established reserves known to exist at the end of 1973 [35, p.53]. If t h i s i s indeed the case then i t seems curious that the National Energy Board d e l i v e r a b i l i t y forecast Increases during the i n i t i a l four years. This could be explained by an und e r - u t i l i z a t i o n of current capacity, or a production p r o f i l e which has a f i v e year build-up to peak capacity for new pools. The confusion about the National Energy Board d e l i v e r a b i l i t y series means that I cannot compare the model-generated GASHAX73 against the National Energy Board series. 3 1 This discrepancy does not en t i r e l y prevent me from using the National Energy Board d e l i v e r a b i l i t y forecast, I could s t i l l use the model-generated end-1973 reserve base, the National Energy Board d e l i v e r a b i l i t y forecast as GASMAX73, and then set the model variable RESEXES to be egual to the i m p l i c i t residual stock of unconnected reserves. 69 If current demand, both Canadian and export, exceeds the t o t a l production available from past hocked-up reserves then new reserves are hooked up as needed. These new connections can proceed as long as there remains a stock (RESEXCES in the model) of discovered reserves that are not producing at their potential rates. New additions to the available stock of reserves are provided by increments to proven reserves (RESDISCV) . These new additions can be forecast excgenously (the National Energy Board forecasts are currently used) or assumed to come forth as required (both subject to increasing costs and an ultimate upper l i m i t ) . The driving force behind the annual amount cf natural gas production i s domestic demand by Canada and export demand by the United States. The demand for natural gas by Canadians i s explained within the demand sector of the energy model. The export demand i s an exogenous series representing the actual guantities for the past and scheduled exports under approved contracts for the future. The model keeps track of several other variables. The accumulated production of non-frontier natural gas i s recorded i n the GASACUfH variable. The non-frontier natural gas proven reserve variable (EESBft.SE) accumulates the annual differences between new discoveries and production. The export value of non-frontier natural gas i s included i n the current account balance equation for o i l and gas (XBALGC$) . Figure 4 shows the forecast for domestic natural gas demand, for export demand under approved contracts, and aon-frontier production based on the procedures outlined above. 70 As can be seen from Figure 4, the large drop in natural gas exports in 1990 leads to shut-in capacity, i . e . production capacity i s greater than the demand. It can also be seen that by 1993 the projected demand cannot he met from the projected non-frontier supply. This shortage could be avoided by a combination of augmenting supply through the use of f r o n t i e r natural gas and c u r t a i l i n g the demand through price increases. 71 4.2 a Description of the Price and Cost Variables The major prices used i n the sector are the price of natural gas at the wellhead, which i s derived from the regulated Toronto price by taking away the transportation cost; the regulated natural gas price i n Toronto, which i s obtained by assuming a continuing closing of the Btu eguivalence gap between natural gas and crude o i l ; and the commodity based opportunity price for natural gas (in r e l a t i o n to o i l ) in the Toronto market. These prices are used in the income, taxation, royalty, and rent eguations. For the income, taxation, and rent eguations i t i s necessary to know the costs to the producers of finding, developing, and processing the natural gas reserves. The model variable RESCOST attempts to measure the combined cost for reserves being held by estimating a cost function r e l a t i n g marginal cost to the stock of accumulated discoveries. The variable GascosTM i s defined to represent the marginal real (1976 dollar) cost of discovering, developing, and producing the next mcf of natural gas. The cost relationship i s such that 29 tc f of post-1973 additions to reserves w i l l increase the constant-dollar marginal cost to 1.3 times i t s 1973 value. This cost relationship i s guite rough, and w i l l soon be 72 disaggregated. 3 2 The construction of the cost data and the results of the estimation eguations are detailed i n appendix 4.B. As described i n the appendix, the f i r s t task was to disaggregate the ncn-frontisr petroleum expenditure data into crude o i l and natural gas expenditure data. I used the r a t i o of the development d r i l l i n g footage for natural gas to the t o t a l development d r i l l i n g footage to obtain a s p l i t t i n g r a t i o for exploration, development, and land a c q u i s i t i o n expenditures. I used the r a t i o of the cumulative number of yearly completions of productive natural gas wells over the cumulative t o t a l number of productive wells to obtain a pro-rationing factor for disaggregating the petroleum operating expenditures. A l l of the re s u l t i n g current d o l l a r natural gas expenditures were converted into constant d o l l a r costs using the PGNE deflator. The natural gas expenditure data were separated into four main categories: exploration and development, processing plants, land acg u i s i t i o n and rentals, and operating. The h i s t o r i c a l constant dollar per unit data in each of these categories were used as dependent variables in separate estimation eguations. The actual data used i n the estimation eguations are reported in part V of appendix The r a t i o of the constant d o l l a r expenditure on exploration 3 2 To make the cost r e l a t i o n s h i p more precise i t w i l l probably be necessary to separate B.C. and Alberta, and to treat exploration, development, and gathering and processing as three separate phases i n order to provide a better economic and technical basis for forecasting future costs and a v a i l a b i l i t y of non-frontier natural gas. This research i s currently being done by Bruce Duncan, 73 and development of natural gas reserves to the gross reserve additions of natural gas i s regressed against a l i n e a r function of the cumulative sum of gross natural gas reserve additions. The data set was divided into two periods: 1958-1966 and 1967-1974. The data set was s p l i t i n 1967 because of a str u c t u r a l s h i f t in costs which was evident from the data. The second period has an average marginal cost which i s about four times that of the f i r s t period. The parameter estimates from the second period are used for the forecast period. The expenditures on natural gas plants are estimated separately. The ra t i o of the constant dollar expenditure cn natural gas plants to incremental demand for natural gas i s assumed to be constant.,This functional relationship i s very approximate. The natural gas plant expenditure i s probably related to the price of the natural gas by-products, the sourness of the gas, and to projected future demand. The proportion, estimated over the 1958-1973 period, i s used for the forecast period. During the forecast period the demand for natural gas occasionally declines and then increases again, due to the i r r e g u l a r i t y of the export contracts. Whenever the demand for natural gas declines, the expenditure on natural gas plants i s set to zero and the current amount of excess capacity i s added to any excess capacity that has accumulated from previous years. If the demand for natural gas should increase again, then the accumulated excess capacity declines by the amount of the demand increase; and as long as there exists some excess capacity, the expenditure on natural gas plants i s set to zero. The r a t i o of the constant d o l l a r expenditure on land 74 acqu i s i t i o n and rentals of natural gas to the production of natural gas i s assumed to be constant. Once again, the functional relationship i s very approximate. The expenditure on land acguisition and rentals i s probably related to the discounted stream of expected rents associated with the land. Nevertheless, the crude relationship yields an average value over the 1958-1974 period of 2.5 1961 cents per Mcf, which i s used for the forecast period. The r a t i o of the constant dollar operating expenditure for natural gas to the wellhead production of marketable natural gas i s estimated to be a l i n e a r function of accumulated production. Over the estimation period the per unit operating costs f e l l s l i g h t l y , due, I suppose, to increased technological e f f i c i e n c y . However, during the forecast period I assume that the estimated operating cost of 5.4 1961 cents per Mcf for the l a s t data point w i l l remain constant. 75 4.3 A Description of the Tax and Bent Eguations The model calculates the p r o f i t s and taxes associated with the production of natural gas. The gross production p r o f i t s are found by multiplying the output by the net wellhead price. The net wellhead price i s the gross wellhead price with the following per unit costs subtracted: operating costs, land a c q u i s i t i o n costs and prior to 1974, the royalty payments. Royalty payments have continued to be allowable as a deduction for p r o v i n c i a l tax accruals. In the post-1974 period the producers are allowed to receive a weighted average wellhead price for natural gas, using both the domestic and the export price. The c a p i t a l cost allowance for the investment expenditure i n discovering and developing the reserve stock i s subtracted from the gross production p r o f i t s to get the net taxable production p r o f i t s . The tax payments depend upon the corporate tax schedule for the petroleum industry, and the depletion allowance rate. The November 1974 federal budget introduced the earned depletion allowance (but allowed accumulated post-1969 expenditures) and lowered the maximum depletion rate from 3 3 and 1/31 to 251. The November 1974 federal budget also lowered the marginal corporate tax rate, and reduced the 1001 writeoff provision for development outlays to a 301 rate, while maintaining the 1001 writeoff provision for exploration outlays. The June 1975 federal budget introduced a sp e c i a l resource abatement which af f e c t s the marginal tax rate. In the post-1974 period several transfer payments from p r o v i n c i a l governments to producers were introduced: namely, the Alberta se l e c t i v e royalty 76 r e d u c t i o n , and the B.C. i n d e m n i f i c a t i o n of f e d e r a l taxes to be paid by producers. More d e t a i l s about the t a x a t i o n and r o y a l t y equations are contained i n appendix 4.D. The economic rent equations f o r the n o n - f r o n t i e r n a t u r a l gas s e c t o r are c a l c u l a t e d s e p a r a t e l y f o r the p r o v i n c i a l governments, the f e d e r a l government, producers, and Canadian and United S t a t e s consumers. Each re n t eguation accumulates the year-by-year flows of net r e t u r n s a f t e r deducting the amount th a t each party would have obtained from h i s most obvious a l t e r n a t i v e . The cumulative net r e n t s to each party are compounded forward over the s i m u l a t i o n period using the nominal s o c i a l time preference f a c t o r , STPNOM, which has a value of approximately'11.4%. At the end of the s i m u l a t i o n p e r i o d , the accumulated f u t u r e values of net c o s t s or b e n e f i t s are discounted back at the same nominal s o c i a l rate of time p r e f e r e n c e to o b t a i n net present v a l u e s , as a t the end of 1976, measured i n terms cf 1976 p r i c e s . Since most of the s i m u l a t i o n periods s t a r t i n 1974, the cumulative value of net r e t u r n s t o each party are c a l c u l a t e d f o r the h i s t o r i c a l p e r i o d to provide k i c k - o f f values f o r each re n t equation at the end of 1973. Thus, the rent eguations accumulate r e n t s from 1955 i n the n a t u r a l gas model. The rent a c c r u i n g to the p r o v i n c i a l government i n c l u d e s the l a n d a c q u i s i t i o n payments, r o y a l t y payments and the p r o v i n c i a l share of the d i f f e r e n c e between the a c t u a l tax payments and the tax payments which would accrue on the c a p i t a l i n v e s t e d elsewhere, using the average tax r e t u r n on i n d u s t r i a l c a p i t a l . In the post-1973 p e r i o d the r e n t s a c c r u i n g to the p r o v i n c i a l 77 government are net of the Alberta royalty reduction transfer and the E.C. indemnification transfer. The rent accruing to the federal government i s the federal share of the difference between the actual tax payments and the opportunity cost measure of the average tax paid on an egual c a p i t a l investment elsewhere i n the economy. The t o t a l rent accruing to the producer i s the net taxable production p r o f i t minus the corporate tax payments and minus the opportunity cost of investing elsewhere the c a p i t a l t i e d up i n the holding of reserves, using the average supply price of c a p i t a l to business. In the post-1973 period the rents accruing to the producers are augmented by the Alberta royalty reduction transfer and the E.C. indemnification transfer. Economic rents from non-frontier production accrue to Canadian and United States consumers, as well as to p r o v i n c i a l governments, the federal government and producers. Canadian users of non-frontier gas earn rents to the extent that the regulated price of gas at the Toronto city-gate i s less than the commodity based opportunity price i n Toronto; United States users of non-frontier gas earn rents to the extent that the export price plus the transportation cost to the Chicago market i s l e s s than the commodity based opportunity price of gas i n Toronto. For most of the h i s t o r i c a l period, Canadian users of non-frontier gas earn no rents because I assumed that the delivered price of gas at Toronto i s egual to the commodity based price of gas in Toronto; and, given our transportation cost assumptions, United States users of non-frontier gas earn 78 r e n t s to the extent t h a t the t r a n s p o r t a t i o n c o s t from the f i e l d to Chicago i s l e s s than the t r a n s p o r t a t i o n cost from the f i e l d to Toronto. when the n a t u r a l gas p r i c e i s r e g u l a t e d the rents to consumers are o v e r s t a t e d . The excess i s a f u n c t i o n of the extent t h a t the commodity based o p p o r t u n i t y p r i c e of n a t u r a l gas i s g r e a t e r than the r e g u l a t e d p r i c e at which the user makes h i s consumption c h o i c e . Were he a c t u a l l y charged the tr u e o p p o r t u n i t y v a l u e , h i s consumption would be l e s s than a t the r e g u l a t e d p r i c e . Hence, our c u r r e n t measures of consumer r e n t s are i n s e n s i t i v e to the p r i c e e l a s t i c i t y of demand f o r n a t u r a l g a s . 3 3 In a d d i t i o n to c a l c u l a t i n g r e n t s t o each of the r e s p e c t i v e p a r t i e s , an independent t o t a l r e n t c a l c u l a t i o n f o r a l l p r o d u c t i o n i s made using f u l l commodity based p r i c i n g . T h i s e g u a t i o n , KRENTGAS, determines t o t a l r e n t s from n o n - f r o n t i e r n a t u r a l gas p r o d u c t i o n . I t provides a check of the model's i n t e r n a l c o n s i s t e n c y because i t should sgual the summation cf the i n d i v i d u a l r e n t components. In order to c a l c u l a t e the net b e n e f i t to Canada from n a t u r a l gas p r o d u c t i o n , the t o t a l rent KRENTGAS has s u b t r a c t e d from i t the r e n t s a c c r u i n g t o United S t a t e s consumers ( KRENTC2$ ) and the p r o p o r t i o n of f o r e i g n r e n t s a c c r u i n g i n the n o n - f r o n t i e r producer r e n t s ( KRENTWFS ), based on the percentage of f o r e i g n ownership. The average percentage of 3 3 Ken Hendricks i s working on t h i s problem by c a l c u l a t i n g the area under the demand curve. 79 foreign ownership in petroleum production i s 78.5%. To provide an example, we s h a l l describe in d e t a i l one rent equation. KRENTNF$, the example, calculates rents to producers of non-frontier natural gas. The term J11*KEENTNF$*STPN0M simply compounds annual net returns forward at the nominal s o c i a l time preference rate. To t h i s one adds gross income, 3.65* GASPRO*PGASW (PGASNF i n 1974), and deducts current operating costs and land acqu i s i t i o n expenditures, 3.65*GASPEO* (A (1909)+A (1906) ) * PEXOG /1.56. One then deducts r o y a l t i e s , TBOYLG, corporation tax, TCG AS NF , an opportunity cost of c a p i t a l , A (1890)* PEX0G*RESC0ST , and depreciation, .365* GASPRO / J1I* RESBASE*PEXGG* HESCGST ; and one adds the Alberta selective royalty reduction, REBATE, and the B r i t i s h Columbia indemnification, BCINDM. The rent for each year i s expressed as an end-of-year value by multiplying by STPN0M**.5 . At the end of the f i n a l simulation year KRENTNF$ i s discounted back to y i e l d a net present value as at the end of 1976, measured in terms of average 1976 prices. The equation that performs t h i s operation i s IF K7=M9 THEN KRENTNF$=KRENTNF$/ (STPNOM ** (K7-3)) . In order to get a feeling for the r e l a t i v e magnitudes cf the various rent variables, I w i l l report the discounted present value of a l l the rents, expressed i n end-1976 d o l l a r s . The t o t a l rent accruing from the production of non-frontier natural gas, KRENTGAS, i s approximately 51 b i l l i o n end-1976 do l l a r s . Of this t o t a l , approximately 39 b i l l i o n end-1976 d o l l a r s , or 16%, accrued to Canadians. As mentioned above, the sum of the rents accruing to the producers, federal government, prov i n c i a l 80 governments, Canadian consumers and United States consumers eguals KRENTGAS. For convenience, the rents w i l l be reported as a percentage of KRENTGAS. The rents to the producers of non-frontier natural gas amount to approximately 19%; to the pro v i n c i a l governments, 42%; to the federal government, 15%; to the Canadian consumer, 15%; and to the United States consumer, 9%. 81 5. Non-frontier Conventional Crude O i l Production The non-frontier conventional crude o i l production sector explains the annual production flows; the costs of discovering, developing and producing; the net producer incomes, taxation payments, and royalty payments; the rents accruing to the major participants i n crude o i l production and consumption; and the accumulation of certain stock variables. The h i s t o r i c a l data, up to 1974, which were used to evaluate the variables in the model were obtained from the Canadian Petroleum Association, S t a t i s t i c a l Yearbook , This sector only explains production and associated variables from non-frontier conventional sources. Therefore the production variable i s net of any production from Great Canadian O i l Sands (GCOS) , Syncrude, and ether synthetic o i l projects. A l i s t of the endogenous and exogenous variables and c o e f f i c i e n t s used i n the non-frontier conventional crude o i l production sector are reported in appendix 1.C. A l i s t of the actual simulation equations contained i n the crude o i l sector are reported i n appendix 2.C. The construction of the h i s t o r i c a l data and forecast assumptions used in the crude o i l sector are contained in appendix 4.A. The construction and sources for the c o e f f i c i e n t s used i n the crude o i l sector are contained i n appendix 4.B and appendix 4.C. The results cf the forecast solution are contained in appendix 5.B. 82 5.1 a Description of the Production Process The production of crude o i l i s assumed to conform to a r i g i d skewed pattern which was reported in an Energy Policy for Canada-Phase J [31, Vol I I , p.80]. The detailed production p r o f i l e for a t y p i c a l pool of crude o i l consists of a one year build-up to the peak annual rate of 7.3% of i n i t i a l recoverable reserves. The peak rate la s t s for 8 years, followed by an exponential decline of 15% per year u n t i l a l l of the i n i t i a l recoverable reserves are extracted after 25 years. 3* Production in the current year draws units from reserves hooked-up in each period over the l a s t 25 years. Since the simulation experiments t y p i c a l l y start well after the i n i t i a l development of Canadian non-frontier reserves, a variable (0ILMAX74) i s defined to represent potential future annual production from a l l reserves connected before the simulation begins. The option exists to use either a model-generated or an exogenous series for CILMAX74. For the current policy simulations I am using an exogenous forecast by the National Energy Board [36, p. 87]. The National Energy Board forecast of crude o i l p r o d u c i b i l i t y from established reserves i s used because i t has been derived from pocl-by-pool data. The reserve base used by the National Energy Board is approximately 2.5% lower than the reserve base calculated from the h i s t o r i c a l 3 * The only a l t e r a t i o n to the pattern reported in the EMR study £ 31 ] was to cut the i n i t i a l build-up from 2 years to 1 year which i s consistent with other studies (AERCB [7] and Kalymon and Quirin [ 93 ]) . 83 simulation of the crude o i l model. The pattern cf p r o d u c i b i l i t y decline i s s l i g h t l y greater in our model than the National Energy Board decline pattern. If the current demand for Canadian ncn-frontier crude o i l exceeds production available from past hocked-up reserves then new reserves are added as needed. If current demand i s less than QILMAX74 then the difference i s added to the variable OIIBEXES which represents the stock of discovered reserves that are not presently hooked-up. This condition prevails for some time after 1974 because exports to the United States are declining much more rapidly than Canadian demand i s increasing. The extent of the shut-in capacity can be observed by comparing the difference between OILMAX and OILPRO in the base case forecast recorded in appendix 5.B. If current demand for Canadian o i l i s less than the production available from OILMAX74 plus reserves hooked up during the simulation run, then the production provided by reserves connected in each of the previous years i s reduced by a certain percentage so that the demand i s just met. The production that has been shut-in by t h i s method i s used to increase a l l subseguent flows from the reserve increments i n question, by amounts that t o t a l the current excess capacity. Thus there e x i s t s two methods for treating excess capacity, one applying to production from reserves hooked up during the simulation, and the other coming into play only i f demand i s l e s s than potential production (e.g. OILMAX74 ) from reserves hooked up before the start of the simulation. New connections can be made as long as there e x i s t s a stock of discovered unconnected reserves, OILREXES. New additions to 84 the available stock of proven reserves are currently provided by an exogenous discovery variable, OILRDISC, which has been obtained by using the Gulf series reported in the National Energy Board 1975 report, Canadian O i l : Supply and Requirements £36, p. 26]. The accumulation of the new discoveries from 1975-1994, reported by Gulf i s 2.019 b i l l i o n barrels (Bbbl) compared with 1.533 Bbbl forecast by the National Energy Board £36, p.26] and 6.2 Bbbl of post-1973 additions forecast i n 1973 by the Department of Energy, Mines, and Resources [31, Vol 1, p.89]. The desired flow cf ncn-frentier production i s based on Canadian demand west of the Ottawa Valley l i n e , approved exports of crude o i l , and desired pipeline throughput to Montreal, less any production forthcoming from Great Canadian O i l Sands (GCOS), Syncrude, and any possible subseguent o i l sands plants. The export demand i s an exogenous series representing the actual guantities during the h i s t o r i c a l period, and the National Energy Board (1975) export forecast during the future period. Exports of crude o i l are forecast to decline very sharply, being almost completely eliminated by 1981 (National Energy Board 1975, p.46). The Canadian demand for crude o i l i s explained within the demand sector of the energy model. I t i s assumed that as long as possible Canadian production w i l l be used to s a t i s f y demand west of the Ottawa Valley l i n e , and beginning i n mid-1976 to supply 250 thousand barrels per day to the Montreal market. As soon as Canadian production can no longer s a t i s f y a l l of these markets, the Sarnia-Montreal pipeline flow eastward i s assumed to decline u n t i l the whole of the western market cannot be met from 85 Canadian production, in which case the Sarnia-Montreal pipeline reverses i t s flow to provide offshore o i l to Ontario, It i s assumed that the demand for crude o i l i n the eastern regions of A t l a n t i c and Quebec w i l l be met by offshore sources (Middle-east and Venezula), except to the extent that western Canadian o i l i s made available through the Montreal pipeline. The model keeps track of several other variables. The accumulated production of non-frontier crude o i l i s recorded in the OIIACOM variable. The non-frontier crude o i l proved reserve variable (0ILR8ASE) accumulates the annual difference between new discoveries and production. The export and import values for crude o i l are included in the current account balance eguation for o i l and gas (XEALGO$) . The model contains variables which represent the federal government subsidy payments to eastern Canadian consumers (GFSUBO) and the federal government revenue from the export tax on crude o i l (TXOIL). From 1975-1980 the subsidy payments w i l l exceed the expert tax revenues by 200-400 million d o l l a r s . The federal government covers part of t h i s d e f i c i t with revenue from the excise tax on gasoline sales [32, p.114-117], a variable which i s not included i n the model. The l a t e s t Department of Energy Mines and Resources report provides estimates for the trade account balance for each major energy f u e l , but unfortunately the forecast values are expressed i n constant 1975 d o l l a r s [32, p.112-114]. For the sake of comparison, I used the model-generated PGNE series to convert the Department of Energy Mines and Resources values from 1975 d o l l a r s to current d o l l a r s . From 1974-1980, the model-generated forecast for XBALGG$ i s 86 s l i g h t l y lower than the Department of Energy Mines and Besources forecast. I have assumed a s l i g h t l y lower p r o f i l e of natural gas exports and s l i g h t l y longer adjustment period for the natural gas export price, and a lower domestic demand for crude o i l . The l a t t e r difference i s , I believe, especially important i n leading to a growing divergence between the two r e s u l t s , such that by 1985 the Department of Energy Mines and Resources value i s approximately 1,400 m i l l i o n d ollars above my value. The model-generated forecast indicates that the d e f i c i t in the current account balance of o i l and gas trade w i l l increase as exports of both o i l and gas decline to zero and the imports of o i l increase as the Montreal-Sarnia pipeline flows westward. Figure 5 shows the pattern of desired production, available capacity, domestic and export demand, and Montreal pipeline throughput obtained using the assumptions and procedures described above. The amount of shut-in crude o i l production can be seen by examining the difference between l i n e 1 and l i n e 2 up to 1981. The shut-in capacity i s due to the sharp f a l l in exports to the United States, as can be seen by viewing l i n e 4. I f one continues to examine lin e 1 and line 2 then one observes that from 1984 they again diverge, but t h i s time production capacity i s less than desired production. This apparent shortage i s made up by adjusting the flow through the Montreal-Sarnia pipe l i n e . By examining lin e 5 one observes that the flow through the Montreal-Sarnia pipeline i s constant at 250 Mbbl/d from 1977 to 1984, and then begins to decline as crude o i l o r i g i n a l l y destined for Montreal i s used to s a t i s f y the s h o r t f a l l in western demand (line 2 minus l i n e 1), and f i n a l l y a f t e r about 87 1988 the pipeline flow i s reversed and offshore crude o i l i s used to s a t i s f y western demand. Line 3 represents the demand for crude o i l west of the Ottawa valley, and l i n e 6 represents t o t a l Canadian demand, hence the difference between l i n e 6 and l i n e 3 i s the demand east of the Ottawa Valley. The sum cf western Canadian demand (line 3), export demand (line 4) and the Montreal-Sarnia eastward pipeline flow (line 5) equals the non-frontier conventional crude o i l production (line 2) minus the o i l sands production (not separately shown on the graph). I t can be seen that after 19 84 the difference between western Canadian demand (line 3) and desired non-frontier conventional production (line 2) i s supplied by o i l sands production (GCCS and CPBOSOM). 88 5.2 A Description cf the Price and Cost Variables Since late 1S73 the Canadian federal government has enforced a two-price policy for crude o i l : the Canadian crude o i l price has been lower than the international price. As part of t h i s system, the federal government has made subsidy payments to eastern r e f i n e r i e s using offshore o i l . Since Canada charges the international price for exports of crude o i l to the United States, the federal government c o l l e c t s revenue through the export tax. The export tax i s set endogenously so that Canadian crude o i l i s priced competitively, after allowing f or transportation t a r i f f s , with the international crude o i l in the Chicago market. The assumption i s made that the Canadian ncn-frontier crude o i l price (measured in the eastern market) w i l l be increased to the international crude o i l price by 1980. It i s also assumed that the international crude o i l price w i l l remain fixed i n r e a l terms at $13/bbl i n 1976 d o l l a r s . When the Canadian price has increased to the international price, the subsidy payments and export tax receipts e f f e c t i v e l y drop to zero. For the taxation and rent eguations i t i s necessary to know the costs to producers of finding and developing past and future crude o i l reserves. The model variable OILRCOST attempts to measure the combined cost of holding reserves by estimating a cost function r e l a t i n g marginal costs to the stock of accumulated discoveries. The variable OILCOSTM i s defined to represent the marginal real (1976 dollar) cost of discovering, developing and producing the next barrel of crude o i l . The cost 89 relati o n s h i p i s such that 2.2 b i l l i o n barrels of post-1973 additions to reserves w i l l increase the constant-dollar marginal cost to 2.2 times i t s 1973 value. The construction of the cost data and the results of the estimation equations are detailed i n appendix 4.B. As described i n the appendix, the f i r s t task was to disaggregate the non-frontier petroleum expenditure data into crude o i l and natural gas expenditure data. I used the r a t i o of the development d r i l l i n g footage for crude o i l to the t o t a l development d r i l l i n g footage to obtain a s p l i t t i n g r a t i o for exploration, development, and land acguisition expenditures. I used the r a t i o of the cumulative number of yearly completions of productive crude o i l wells over the cumulative t o t a l number of productive wells to obtain a pro-rationing factor f o r disaggregating the petroleum operating expenditures. A l l of the r e s u l t i n g current d o l l a r crude o i l expenditures were converted into constant d o l l a r costs using the PGNE deflator. The crude o i l expenditure data were separated into three main categories: exploration and development, land acguisition and rentals, and operating. The h i s t o r i c a l constant dollar per unit data i n each of these categories were used as dependent variables in separate estimation eguations. The actual data used in the estimation equations are reported in part V of appendix 4,B. The r a t i o of the constant d o l l a r expenditure on exploration and development of crude o i l reserves to the gross reserve additions of crude o i l i s regressed against a l i n e a r function of the cumulative sum of gross crude o i l reserve additions. The data set was divided into two periods: 1958-1966 and 1967-1974, 90 The marginal cost actually f e l l very s l i g h t l y , on average, • during the f i r s t period. But during the second period, the marginal cost rose guite sharply. The parameter estimates from the. second period are used for the forecast period. The r a t i o of the constant d o l l a r expenditure on land a c g u i s i t i o n and rentals of crude o i l to the production of crude o i l i s assumed to be a l i n e a r function of cumulative production. The functional r e l a t i o n s h i p i s very approximate. The expenditure on land a c g u i s i t i o n and rentals i s probably related to the discounted stream cf expected rents associated with the land. For the forecast period the l a s t estimated value of .08 1961 $ per barrel i s used, The r a t i o of the constant dollar operating expenditure for crude o i l to the wellhead production of crude o i l i s estimated to be a l i n e a r function of accumulated production. Over the estimation period the per unit operating costs f e l l s l i g h t l y , due, I suppose, to increased technological e f f i c i e n c y . However, during the forecast period i t was assumed that the l a s t estimated operating cost of .20-1961 $ per barrel w i l l remain constant. Due to the fact that o i l wells w i l l probably be operating with excess capacity from 1975 to 1980, I should probably have assumed that the last h i s t o r i c a l value of .26 1961 $ per barrel would remain constant. 91 5,3 A Description of the Tax and Rent Equations The taxation and rent eguations for crude o i l production have been developed analogously to the natural gas taxation and rent eguations. Hence the general description of the taxation and rent eguations contained in chapter 4, section 4.3, and in appendix 4.D are applicable to this section. Economic rents accrue to Canadian consumers of non-frontier o i l , but not to United states consumers. The United States users of ncn-frontier o i l do not earn rents because I assume that the o i l export tax eguals the difference between the price of i n t e r n a t i o n a l o i l delivered to United States markets and the delivered price of non-frontier o i l . During the h i s t o r i c a l period, Canadian users of non-frontier o i l earn negative rents to the extent that the domestic o i l price i s less than the i n t e r n a t i o n a l price of o i l delivered to Canadian markets east of the Ottawa Valley; and, United States consumers of non-frontier o i l earn no rents because It i s assumed that the Canadian wellhead price of o i l was set competitively with the United States domestic crude o i l price. In order to get a f e e l i n g for the r e l a t i v e magnitudes of the various rent variables, I w i l l report the discounted present value of a l l the rents, expressed i n end-1976 d o l l a r s . The t o t a l rent accruing from the production of non-frontier conventional crude o i l , KRENTOIL, i s approximately 61 b i l l i o n end-1976 do l l a r s . Of t h i s t o t a l , approximately 58 b i l l i o n end-1976 d o l l a r s , cr 96%, accrued to Canadians. The sum of the rents accruing to the producers, federal government, provincial 92 governments, and Canadian consumers eguals KRENTOIL. For convenience, the rents w i l l be reported as a percentage of KRENTCIL. The rents to the producers of non-frontier conventional crude o i l amount to approximately 5%; to the p r o v i n c i a l governments, 65%; to the federal government, 1 1 % ; and to the Canadian consumer, 20%. 93 6. Policy Analysis As indicated i n the introduction, the annual energy model i s set up to f a c i l i t a t e the analysis of the effects of di f f e r e n t p r i c i n g , taxation, and development strategies for Canadian natural gas and crude o i l , Using so-called 'base case' assumptions about world and Canadian energy prices, and assumptions about future reserve additions and costs, I have computed a forecast to 1995 which i s reported i n appendix 5.B. The detailed assumptions behind the base case forecast are contained i n appendices 4 and 5.A. This 'control solution' i s used as a basis for measuring the e f f e c t s on economic costs and benefits of the various policy alternatives. The major policy thrusts of the Canadian government, as mentioned in the Department of Energy Mines and Resources report £32, part IV, ch. 3-4], are to ensure appropriate energy p r i c i n g , to encourage energy conservation, to fes t e r appropriate i n t e r f u e l substitution, and to develop new delivery systems. The s p e c i f i c targets of these policy thrusts are to move o i l prices towards international l e v e l s and move gas prices to an appropriate competitive relationship with o i l prices over the next 2-4 years; to reduce o v e r a l l energy growth to an average annual rate of 3.5%; to reduce dependence on imported o i l in 1985 to one-third of our t o t a l o i l demand; and to construct the Sarnia-Montreal pipeline by mid-1976 and to construct a Mackenzie pipeline when desired. As a policy prescription I have used the federal government's assumptions about appropriate energy pricing i n the base case model solution. With regard to 94 the annual 3.51 target rate of energy demand growth, one notes that the federal government i s assuming a 3.61 average annual rate of growth of rea l GNE (with no r e l a t i v e price changes), whereas In my base case forecast I have approximately a 4.71 average annual growth rate in t o t a l energy demand with a 4.51 average annual rate of growth of r e a l GNE (with no r e l a t i v e price changes). In the base case forecast the model predicts that the percentage of o i l imports to t o t a l o i l demand i s approximately 381 in 1985, but t h i s percentage r i s e s quickly a f t e r 1985 as the Sarnia-Montreal pipeline reverses i t s flow as western crude o i l production declines. I include the Sarnia-Montreal pipeline in the base case forecast, but test the implications of delaying i t s existence u n t i l a westward flow i s needed. I w i l l experiment with variations of these and other p o l i c i e s . As explained by Crommelin [43, p.6-16], the s p l i t in government j u r i s d i c t i o n , between federal and p r o v i n c i a l , over petroleum resources i s such that the provinces own the resource; but the s p l i t i n l e g i s l a t i v e authority i s such that powers of management and sale rest with the provinces, and the control over inter provincial and external trade and commerce, pri c i n g , taxation and i n t e r p r o v i n c i a l pipeline transportation rest with the federal government. I am not interested i n exploring any policy alternatives r e l a t i n g to the management decisions of the pr o v i n c i a l governments. I am interested i n most areas of federal government co n t r o l , with the notable exception of taxation pol i c y . Taxation policy i s ignored because I have not yet spe c i f i e d endogenous behaviour for the exploration and 95 development functions i n the petroleum supply sector. The only policy variation that I consider with regard to i n t e r p r o v i n c i a l pipeline transportation relates to the construction of the Sarnia-flontreal pipeline. Therefore I intend to concentrate the experimentation with federal government policy alternatives r e l a t i n g to energy p r i c i n g and external trade. In order to compare the res u l t s of the various policy a l t e r n a t i v e s , which w i l l probably have different time paths, I w i l l often refer to a present value measure. The present value measure quantifies into a single number the time stream of re s u l t s for a variable, As a summary of the policy e f f e c t s I w i l l often refer to the present value of the economic rents accruing to the major participants: producers, governments, and consumers. The construction of the rent measures are described i n section 4.3 and section 5,3. o 96 6.1 Background Literature on Trade and Price P o l i c i e s F i r s t l y I w i l l examine the l i t e r a t u r e which deals with government p o l i c i e s r e l a t i n g to trade flows, and then examine the l i t e r a t u r e which relates to pricing p o l i c i e s . Most of the l i t e r a t u r e describing trade flows i n crude o i l and natural gas between Canada and the United States has emphasized the r e s t r i c t i o n s placed on the free flow cf products. The quantity of natural gas exports has been r e s t r i c t e d through the National Energy Board's exportable surplus policy (Bradley [21], and Hamilton [67]); the guantity of crude o i l exports has been limited somewhat by the United States quota i n 1959 and from 1967-1973, and by the Canadian guotas i n 1975 (NEB [34], Debanne [50], McDougall [106], United States Task Force report [149], and Saverman [157]); and the quantity of imports of crude o i l has been limited by the creation of the National O i l Policy i n 1961 (Debanne [50], Hamilton and Schwartz [68], Ritchie [122], and Waverman [157]). A few studies examine the problem of market a l l o c a t i o n of domestic production among domestic use, export or import replacement (Anderscn[9 ], Hamilton and Schwartz [68], Powrie and Gainer [118], and Haverman [ 155, 156]). The major d i f f i c u l t y associated with most of these studies i s that they only estimate the net cost for one year, ignoring replacement cost due to depletion. The Royal Commission on Energy [37] recommended that the NEB be e s t a b l i s h e d 3 5 to regulate natural gas exports through 3 5 The NEB was established in 1959. 97 l i c e n s i n g , so that only natural gas which i s surplus to the reasonable foreseeable reguirements of Canada would be exported. The NEB calculates i t s exportable surplus as any excess of established reserves over Canadian requirements. 3 6 Clearly there must be an i m p l i c i t assumption that the production flow of natural gas has a li f e t i m e of 30 years because the exportable surplus rule compares a stock with a flow. Bradley [21] has c r i t i c i z e d the rule for f a i l i n g to take account of i n t e r f u e l substitution and technical change i n forecasting consumption, for f a i l i n g to take any account of price e l a s t i c i t y of reserves supplied, and for f a i l i n g to appreciate the s i g n i f i c a n c e of the cost cf holding a large working inventory of reserves. The Boyal Commission on Energy [37] also recommended an expansion of domestic crude o i l production which would be used to displace imports i n the Ontario market. This recommendation led to the government establishing the National O i l Policy in 1961 which guaranteed domestic producers a marketing area west . of the Ottawa Valley. From 1959-1974 the NEB placed no controls on crude o i l exports because no shortage was envisioned. In f a c t , the government encouraged the expansion of Canadian exports of crude o i l to the United States. Bradley [22] explains a p o s s i b i l i t y for the government actively t r y i n g to expand the market f<9r domestic production, Pro-rationing, although eliminating some cf the physical waste in the 'rule of capture 1, 3 6 Established reserves are defined as a l l current proved reserves and a f r a c t i o n , usually 50%, of current estimated probable reserves. Canadian requirements are defined as 30 times the current consumption for Alberta, and 25 times the estimated fourth year consumption for the rest of the country [21, p.8], 98 s t i l l tends to lead to economic waste in terms of overinvestment i n d r i l l i n g . This excess.capacity has led to government action i n Canada to expand the market si z e ; and incidently the same excess capacity phenomenon has led to a protected United States market through import guotas. Another possible reason for the government attempting to both increase crude o i l exports and decrease crude o i l imports by r e s t r i c t i n g the Ontario market was to help a l l e v i a t e the current account d e f i c i t that was r e l a t i v e l y large from 1956-1961. The balance of payments effects due to d i f f e r e n t l e v e l s i n the current account have been discussed i n McDougall [106] and Laxer [100]. They argue for a curtailment of Canadian exports of natural gas and crude o i l to the United States because over the past few years the Canadian d o l l a r has been appreciating due to the current account surplus. The exchange rate appreciation i s causing Canadian manufacturing exports to become less competitive, which i s alleged to have detrimental e f f e c t s to the aggregate employment and income le v e l s in Canada. A study by Powrie ana Gainer [118] examines the implications of alternative policy options (guotas, export tax, subsidies, l a i s s e z - f a i r e ) with regard to projected trade patterns i n crude o i l and natural gas i n 1980. They consider the production implied for each element of a matrix with d i f f e r e n t growth rates for imports and exports, given the assumption of a constant growth rate in domestic demand of 5.5% per year. They l i m i t the choice of import-export growth rates by examining the h i s t o r i c a l growth in reserves and extrapolating for 1972-1980, and then assuming a minimum reserves/production r a t i o of 10/1. 99 They have not considered the costs associated with d i f f e r e n t l e v e l s of production; they have not assessed the impact of price changes on the supply or demand; they have not examined the p o s s i b i l i t y of substitution between crude o i l and natural gas; nor have they provided a guantitative measure of the macroeconcmic impact. Next I w i l l examine two studies which indicate the potential importance of a Canadian pricing policy involving the use of an export tax on crude o i l . Schwartz [125] presents an assessment of the effect that various l e v e l s of an export tax would have on the United States demand for Canadian crude o i l . For the year 1969 he calculated the optimal export tax: the tax that maximizes the t o t a l export sales revenue (i.e. the export tax revenue plus the producers net revenue). The United States demand schedule i s constructed by postulating that the e l a s t i c i t y of demand I s determined by the competitive position of Canadian crude o i l r e l a t i v e to United States crude o i l . He examines the sources and costs of crude o i l from various producing regions for f i v e major r e f i n i n g areas currently served by Canadian exports. The export tax i s assumed not to af f e c t the Canadian wellhead price, or the United States wellhead price. For 1969 the optimal export tax i s $.46/bbl (in Canadian d o l l a r s ) , which would y i e l d a tax revenue of $86 mill i o n . In a somewhat broader study of Canadian p r i c i n g p o l i c i e s , Anderson [9] claims that an average annual net gain of $101 mil l i o n could have been obtained over the period 1963-1970 by the removal of protection of the National O i l Policy and the addition of an export tax. 1 0 0 The actual government export p o l i c i e s have tended to favour guotas: for example, c u r t a i l i n g the issue of new export licences for natural gas, and phasing cut of crude o i l exports. Since 1974 there has been both an export tax and an export guota on crude o i l . Of course, only one of these constraints can bind; and i f i t i s the guantlty constraint that binds then the policy i s sub-optimal. It would be desirable to estimate eguations that represent the United States demand for Canadian exports of crude o i l and natural gas. If one had such United States demand eguations then i t would be possible to guantify the ef f e c t on the export demand through any Canadian government policy which affects the export price - an export tax, for example; and i t would be possible to compare the desired export l e v e l (for given Canadian prices) to the actual l e v e l of exports i f the Canadian government policy i s to r e s t r i c t the guantity of exports through quotas rather than price adjustments. But these desired United States demand eguations are d i f f i c u l t to formulate without undertaking a ca r e f u l study of a set of demand eguations for a l l substitutable primary fuels i n the northern United States region. A wide range of market r e s t r i c t i o n s , in the form of both a guota and export tax, have been imposed by both the Unitsd States and Canada over most of the h i s t o r i c a l estimation period [ 9 ] , The problem of guantities r e s t r i c t e d by guotas, coupled with the d i f f i c u l t y of obtaining regional United States data on energy prices and demands has unfortunately led me to abandon any attempt to estimate United States demand eguations. The federal government pri c i n g policy i n i t a t i v e s have begun 101 only recently. Prior to August 1973, the federal government played no direc t role in c i l or gas price setting. In the EMR study [31] i t i s reported that "for a l l intents and purposes foreign purchasers of Canadian crude o i l pay the posted price plus freight to destination. Posted prices i n Canada are set at Edmonton. The prices are such as to make the product competitive when l a i d down i n the Chicago market" [31, Vol.1, p.250], Eut since October 1973 the wellhead price of crude o i l i n Canada has been held below the world price. The domestic wellhead price was frozen at $3,80/bbl from September 1973, and increased to $6.50/bbl i n May 1974, and then to $8.00/bbl in July 1975. From May 1974 the price f o r crude o i l has been regulated such that in a l l regions of Canada i t i s egual to the wellhead pries plus transportation, through federal government subsidy payments to regions which Import crude o i l . Since 1974 the federal government has regulated the Toronto city-gate natural gas price. The federal government has also been involved i n regulating the export price through imposing an export tax on crude o i l and a l t e r i n g contracted natural gas export prices. Most of the post-1973 policy i n i t a t i v e s are summarized in the l a t e s t Department of Energy Mines and Resources report [32], The market price used i n simulating the demand for the primary products w i l l be determined from exogenous data. The price of crude o i l w i l l be based on the offshore price, or else w i l l be set at the l e v e l determined by the federal government for a l l regions of Canada, The price of natural gas w i l l be related to the price of crude o i l through assuming various degrees of Btu eguivalence i n the central Canadian market, Eut 102 i f the wellhead p r i c e i s d e r i v e d from exogenous data how can a long-run e q u i l i b r i u m s i t u a t i o n be p o s s i b l e ? The long-run e q u i l i b r i u m would be c h a r a c t e r i z e d by a l l consumers (Canadian and United S t a t e s consumers of Canadian p r o d u c t i o n , and Canadian consumers of f o r e i g n production) having t h e i r demands s a t i s f i e d , and a l l producers j u s t meeting the d e s i r e d demand a t the market p r i c e s . In the case of crude o i l i t appears as i f government p o l i c y has t r i e d to s h i f t the demand f o r imports or exports to l e a d to an e q u i l i b r i u m s i t u a t i o n . I f the wellhead p r i c e i s too high i t may l e a d to an excess d i s c o v e r y of new r e s e r v e s . T h i s w i l l l e a d to a combination of the f o l l o w i n g government p o l i c i e s : p r o - r a t i o n i n g of demand among producers, expanding the export market or expanding the domestic market through import replacement. I f the wellhead p r i c e i s not high enough to encourage the e x p l o r a t i o n f o r s u f f i c i e n t new r e s e r v e s then the a v a i l a b l e supply must be r a t i o n e d among the domestic and export market, or the import market must expand. In the case c f n a t u r a l gas there w i l l not be any adjustment p o s s i b l e through the import market. Seme of the h i s t o r y of Canadian p o l i c y i n crude o i l and n a t u r a l gas from 1958 onward, summarized e a r l i e r i n t h i s s e c t i o n , v e r i f i e s t h a t the Canadian government p o l i c y has a c t u a l l y f o l l o w e d some of these g u a n t i t y adjustment o p t i o n s . 103 6.2 The Simulated Energy Demand E l a s t i c i t i e s The major impacts of alternative energy p r i c i n g p o l i c i e s are f e l t through changes in the d i s t r i b u t i o n of economic rents and changes in the quantities of energy fuels demanded. With regard to the l a t t e r e ffect i t i s useful to know the own and cross price e l a s t i c i t i e s of demand. The knowledge of the e l a s t i c i t i e s w i l l give one some idea about the size and di r e c t i o n of energy pricing p o l i c i e s . The. demand model described i n chapter 2 and appendix 1.A, appendix 2.h, and appendix 3 i s used to generate the ef f e c t s of a 10% decrease i n energy prices holding a l l other exogenous variables constant. The simulation r e s u l t s for the year 1985 are reported in Table 1. 3 7 The table consists of two parts: the f i r s t part contains the e f f e c t s cn the f i n a l demand for primary energy fue l s (excluding the fuels used to generate thermal e l e c t r i c i t y ) ; the second part contains the e f f e c ts on the energy use of primary energy fuels (including the fuels used to generate thermal e l e c t r i c i t y ) . Each part of Table 1 contains the percentage quantity e f f e c t for each of the primary fuels (along each row) for a given percentage price change for each of the fue l s . The numbers in Table 1 are not labelled as demand e l a s t i c i t i e s 3 8 even though they represent a percentage change in 3 7 The simulations necessary to generate the values In Table 1 were run by Ken Hendricks. 3 8 For expcsitional purposes I w i l l refer to the r a t i o of the percentage guantity adjustment over the percentage price change as a 'simulation e l a s t i c i t y ' . It i s derived by dividing the elements reported i n Table 1 by -10. 104 quantity induced by a percentage change i n price because the price change induces both a s h i f t i n the t o t a l demand for energy and a s h i f t i n the r e l a t i v e shares. Therfore the simulation e l a s t i c i t i e s reported i n Table 1 are not eguivalent to those reported i n appendix 3.B. But other d i f f i c u l t i e s e x i s t i n attempting a dire c t comparison of the e l a s t i c i t i e s : for example/ the numbers in Table 1 are aggregated for a l l Canada, whereas the appendix 3.B e l a s t i c i t i e s are regional; and the price e l a s t i c i t i e s can vary over time. Since the e l a s t i c i t y of t o t a l energy demand with respect to the energy price index i s negative, t h i s implies that increases or decreases in energy f u e l prices w i l l lead to simulation e l a s t i c i t i e s that are larger i n absolute value than the p a r t i a l e l a s t i c i t i e s reported in appendix 3.B when the p a r t i a l e l a s t i c i t i e s are negative, and may be larger or smaller when the p a r t i a l e l a s t i c i t i e s are positive. In examining the f i r s t part of Table 1 one notices that a change i n the price of coal has no effect on any other fuels and that a change in any cf the fuel prices has no effect on the quantity cf coal demanded. Since the f i r s t part of Table 1 only includes the f i n a l energy demand and since coal i s endogenously modelled only i n the market for the thermal generation of e l e c t r i c i t y , price changes have no effect on the demand for coal. I assumed that coal does not compete as a substitute in the non-thermal markets, hence i t s price does not enter into the demand equations for other fuels. Continuing to examine the f i r s t part of Table 1 one notices that the own simulation e l a s t i c i t i e s are -.483 for e l e c t r i c i t y , -1.08 for natural gas, and -.54 for crude o i l . The simulation 105 cross price e l a s t i c i t y of e l e c t r i c i t y with respect to natural gas i s +.066 and with respect to crude o i l i s -.089. The simulation cross price e l a s t i c i t y of natural gas with respect to e l e c t r i c i t y i s +.277 and with respect to crude o i l i s +.267. The simulation cross price e l a s t i c i t y of crude o i l with respect to e l e c t r i c i t y i s +.028 and with respect to natural gas i s +.059. a l l of the simulation cross price e l a s t i c i t i e s indicate substitution between f u e l s , except for the cross price e l a s t i c i t y of e l e c t r i c i t y with respect to crude o i l . The reason for the negative sign, when the price of crude o i l f a l l s , i s that the increase in the demand for e l e c t r i c i t y due to the increase in the o v e r a l l energy demand i s greater than the decline in the demand for e l e c t r i c i t y due to substitution of crude o i l for e l e c t r i c i t y . S t i l l examining the f i r s t part of Table 1 one notices that the simulation price e l a s t i c i t y of t o t a l energy consumption with respect to e l e c t r i c i t y i s -.029, with respect to natural gas i s -.269, with respect to crude o i l i s -.164, and with respect to a l l energy prices i s -.448. The overall decrease in the price of a l l energy fue l s , through i t s e f f e c t of increasing t o t a l energy demand, leads to simulation e l a s t i c i t i e s of e l e c t r i c i t y with respect to a l l prices of -.4 38, of natural gas with respect to a l l prices of -.542, and cf crude o i l with respect to a l l prices of -.462. In examining the second part of Table 1 one notices that coal i s endogenously determined, and that coal i s considered as a substitute for other f u e l s . But the price of coal s t i l l has no eff e c t on the demand for e l e c t r i c i t y because coal does not enter 106 as a substitute for e l e c t r i c i t y i t s e l f , only as a substitute for the fuels used to generate thermal e l e c t r i c i t y . The own simulation e l a s t i c i t y f or coal i s -.63. The simulation cross price e l a s t i c i t y of coal with respect to e l e c t r i c i t y i s -.121, with respect to natural gas i s +.241, and with respect to crude o i l i s +.412. The simulation cross price e l a s t i c i t y of natural gas with respect to coal i s +.034, and of crude o i l with respect to coal i s +.01. A l l of these simulation cross price e l a s t i c i t i e s r e l a t i n g to coal indicate s u b s t i t u t a b i l i t y between fu e l s except the simulation cross price e l a s t i c i t y of coal with respect to e l e c t r i c i t y . The reason for the seemingly complementary relationship between coal and e l e c t r i c i t y i s that the decline in the price of e l e c t r i c i t y leads to an increase in the demand for e l e c t r i c i t y and hence an increase in the demand for coal used to produce thermal e l e c t r i c i t y , but by assumption does not lead to a counteracting f a l l i n the demand for coal in the non-thermal markets. S i m i l a r i l y the seemingly complementary relat i o n s h i p between crude o i l and e l e c t r i c i t y stems from the fact that the decline i n the price of e l e c t r i c i t y leads to an increase i n the demand for crude o i l used to generate thermal e l e c t r i c i t y which i s greater than the decline i n the demand for crude o i l due to the substitution of e l e c t r i c i t y for crude o i l . The other entries in the second part of Table 1 are very similar to the corresponding entries in the f i r s t part of Table 1, described above. Using the second part of Table 1 one can conclude that a 10% decrease in the price of e l e c t r i c i t y w i l l lead to a 4.8% increase in the amount of e l e c t r i c i t y demanded. Using both parts 107 of Table 1 i t i s possible to calculate that a 10% decrease in the price of e l e c t r i c i t y w i l l lead to approximately the following increases i n fuels used to generate thermal e l e c t r i c i t y : a 0.9% increase in crude o i l , a 1.2% increase in co a l , and a 0.6% increase in natural gas. The simulation e l a s t i c i t i e s reported i n Table 1 are a l l approximately within the bounds of Canadian demand e l a s t i c i t i e s reported in the survey by Berndt [17]. It i s d i f f i c u l t to compare the e l a s t i c i t i e s generated from my model to other models because I have aggregated energy use across a l l end-use sectors, whereas most other studies distinguish between sectors. From the r e l a t i v e sizes of the numbers reported in the second part of Table 1 one can observe the following: the own simulation price e l a s t i c i t y of natural gas i s approximately twice as large as either crude o i l or e l e c t r i c i t y ; the cross simulation price e l a s t i c i t i e s of both crude o i l and e l e c t r i c i t y with respect to natural gas are approximately the same size and very small; both the simulation cross price e l a s t i c i t i e s of e l e c t r i c i t y with respect to crude o i l and of crude o i l with respect, to e l e c t r i c i t y are very small and indicate complementarity; the simulation cross price e l a s t i c i t y of natural gas with respect to both e l e c t r i c i t y and crude o i l are r e l a t i v e l y large and roughly of the same magnitude. Hence one observes that the only cross demand e f f e c t s of any significance to a r i s e from pricing decisions involving crude o i l , natural gas, and e l e c t r i c i t y w i l l be the effect on the demand for natural gas due to changes in the price of either e l e c t r i c i t y or crude o i l . 108 Table 1* Ef f e c t s of a 10% Decrease i n Energy Prices on Energy Demand charic]e_ in jguantities demanded Coal Elect Gas O i l Energy price change Co a l 2 0 0 0 0 0 Elect 0 + 4. 83 - 2.77 - .28 + .29 Gas 0 - .66 +10.80 - , 59 + 2.69 o i l 0 + . 89 - 2. 67 + 5. 40 + 1.64 fill 0 + 4. 38 + 5.42 + 4,62 + 4.48 Effects Of A 10% Decrease In Energy Prices On Energy Use (including fuels used i n generation of thermal e l e c t r i c i t y ) £~rcentage change in quantities demanded Coal Elect Gas O i l jarice chancje Coal +6.30 0 - . 34 - .10 Elect +1.21 +4.82 -2,13 + .65 Gas -2.41 - .66 +10.14 - .62 O i l -4.12 + .90 - 2.23 +5.60 A l l +4.85 ' +4.37 + 5.52 +5.55 where: elec t i s used to represent e l e c t r i c i t y , gas i s used to represent natural gas, o i l i s used to represent crude o i l . 1 The year 1985 i s chosen for the calculation to permit a l l lagged e f f e c t s to be worked out. Consequently the federal government's policy of reaching world-level price equivalence by 1981 w i l l have no impact cn the calculations. The base case assumes a price l e v e l consistent, i n terms of commodity value, with the world o i l price. 2 The model assumes that coal i s an intermediate f u e l used only i n the generation of thermal e l e c t r i c i t y . Hence the n i l e f f e c t of price changes cn the demand for coal. 109 6.3 A S e n s i t i v i t y Analysis of Some Factors Affecting the Demand System The description of the exact changes made to the demand sector in order to generate the six s e n s i t i v i t y experiments i s contained in appendix 6.A. The results of the six s e n s i t i v i t y experiments are reported in the f i r s t part of appendix 6.B. The rate cf growth of real GNE i s a very important variable in the demand system, especially after 1981 when there i s v i r t u a l l y no change i n r e l a t i v e prices. Conseguently, the f i r s t three s e n s i t i v i t y experiments measure the impact of alternative growth rates for UGNE. The f i r s t experiment uses the 4,5% per year growth rate for UGNE, which i s the rate assumed by the National Energy Board. The second experiment uses the post-1981 growth rate of 3.6% per year, which i s the low economic growth rate assumed by the Department of Energy Mines and Resources; and the th i r d experiment uses the post-1981 growth rate of 5.2% per year, which i s the high economic growth rate assumed by the Department of Energy Mines and Resources. Analyzing the results of s e n s i t i v i t y experiment 1, one notes the following: the percentage change in a l l of the energy expenditures and demand variables grow u n t i l 1981 and then remain constant. The reason for the constancy after 1981 i s that aft e r t h i s year UGNE i s also assumed to grow at 4,5% per year i n the control solution. The expenditure and demand variables gradually build up to roughly a 5.4% divergence with the control solution, which i s the UGNE c o e f f i c i e n t A (2026) multiplied by the average percentage change in the six year divergence between 110 a 5 . 4 1 growth path and a 4 . 5 1 growth path. The t o t a l Canadian demand for o i l and gas (OETU.C and OBTU.G) has declined in percentage terms more than the non-thermal demand for o i l and gas reported in Ontario because less fuel i s demanded for thermal e l e c t r i c i t y generation. The drop in Canadian demand for o i l and gas leads to a decline in Canadian production. The production of o i l and gas does not decline as much in percentage terms as the Canadian demand because the exports of o i l and gas have not changed. The production of both o i l and gas are lower than the control value in the i n i t i a l period and then higher because the ultimate stock of reserves i s not depleted as scon as in the control case. The decline i n the demand for o i l products in eastern Canada leads to lower imports , lower subsidy payments, and an increase in the o i l and gas trade -account. The decline in the demand for o i l products in western Canada leads to an increase in the potential flow of Canadian o i l through the Sarnia-Montreal pipeline. The production decline implies that a l l rent components for both o i l and gas are below the control solution rents. The percentage decline i n producer rents i s larger for crude o i l producers because a larger percentage of o i l production i s for the domestic market. In analysing the results of experiment 2, one notes the following: The pattern of a l l the variables i s very similar to experiment 1, except that the lower growth does not begin u n t i l 1982, and the divergence continues to grow throughout the experiment. Even though the production decline of natural gas i n percentage terms i s larger a f t e r 1986 i n experiment 2, a l l cf the rent components are smaller in absolute value because of the 111 discounting procedure. The crude o i l rent components are much le s s negative i n experiment 2 because the production decline does not begin u n t i l 1982, after which i t i s only three years u n t i l a l l western Canadian demand cannot be met from Canadian sources. In experiment 3, the growth of GNE i s 5.2% from 1981, compared with the control growth of 4.5%. The res u l t s indicate an increase i n the demand for a l l energy fuels. The higher growth begins i n 1982, and the divergence continues to grow throughout the experiment. Even though a l l of the demand variables have the opposite sign to those i n experiment 2, a l l of the comments made about the pattern and r e l a t i v e sizes of the variables are applicable in experiment 3. The increase in natural gas demand i n the post-1982 period leads to a d e f i c i t s i t u a t i o n from ncn-frontier production in 1992, rather than i n 1993. The increase i n western Canadian demand for o i l means that less o i l can be shipped eastward through the Sarnia-Montreal pipeline. The increase in eastern Canadian demand leads to a larger d e f i c i t i n the o i l and gas trade account. The production increase implies that a l l of the rent components for both o i l and gas w i l l increase r e l a t i v e to the control solution. Although of opposite sign, the r e l a t i v e size of the o i l and gas rents are si m i l a r between experiment 3 and experiment 2. A major source of uncertainty i n any forecast of energy prices i s the landed offshore crude o i l price. And the offshore crude o i l price plays an important.role i n the model. It i s used as the opportunity cost measure f o r a l l crude o i l sales. I t i s assumed that the Canadian o i l price w i l l reach the international 112 price by 1980. The offshore crude o i l price i s also used as the basis for evaluating the Etu equivalent natural gas price. The Btu equivalent variable i s used as the opportunity cost measure for a l l natural gas sales, and as the price which the regulated Toronto city-gate price w i l l reach by 1982. The fourth s e n s i t i v i t y experiment assumes that the nominal price of offshore crude o i l remains at i t s 1980 l e v e l , instead of growing at ti% per year. Since the Canadian energy prices are assumed to adjust to world prices not sooner than 1980, there i s no e f f e c t u n t i l 1981. I t should be noted that a change in the offshore price does not automatically lead to any change i n the natural gas price i n B.C., or the e l e c t r i c i t y price i n any of the regions. The decrease in the price of o i l and gas leads to increases in the guantity of o i l and gas demanded, and a decrease in the guantity of e l e c t r i c i t y demanded. The increase i n domestic demand for natural gas leads to a d e f i c i t s i t u a t i o n from non-frontier sources occurring two years e a r l i e r . Despite the increased production of both o i l and gas, the percentage price decline i s larger, leading to a f a l l in the taxable income from o i l and gas production. The balance of o i l and gas trade i s at f i r s t negative, and then p o s i t i v e . In the 1981-1988 period the negative trade e f f e c t of the decrease i n the value of Canadian natural gas exports more than offsets the positive e f f e c t of the decrease i n the value of Canadian imports of crude o i l . As the quantity of natural gas exports f a l l s r apidly i n the early 1990's, the balance of trade on o i l and gas increases r e l a t i v e to the control value. Once again, the producers suffer the brunt cf the decline in the rents generated from o i l and gas 1 1 3 production. In the f i f t h s e n s i t i v i t y experiment i t i s assumed that the nominal price of offshore crude o i l increases at 10% per year after 1981. Such increase in the real o i l price could arise i f a supply shortage were l i k e l y to occur in the 1980*s. The variables have e s s e n t i a l l y the same pattern i n this experiment as in the previous experiment, except with an opposite sign. In the l a s t s e n s i t i v i t y experiment one can examine the e f f e c t s of increasing the e f f i c i e n c y factors for o i l and gas in the non-thermal market uses. I hypothesize that improvements i n gasoline mileage in the transportation sector, improvements in building i n s u l a t i o n , and the use of energy-efficient appliances in the r e s i d e n t i a l and commercial sectors w i l l lead to more e f f i c i e n t use of o i l and gas. A r b i t r a r i l y , I have chosen to study the e f f e c t s of an e f f i c i e n c y increase of .5% per year for both o i l and gas. The Department of Energy Mines and Resources report [32, p. 131-132] mentions increases i n e f f i c i e n c y of energy use higher than .5% per year, but t h e i r increases relate only to new c a p i t a l goods. This shock leads to a decrease in the price per output Etu of both o i l and gas, hence to an increase i n the number of output Btu of o i l and gas demanded and to a decrease in the guantity of e l e c t r i c i t y demanded. However, the proportionate increase in the output Btu demand for o i l and gas i s less than the proportionate increase i n the the e f f i c i e n c y f a c t o r , so that the demand for o i l and gas declines, when measured in natural units. Hence the production of o i l and gas declines. The western Canadian production decline leads to an increase in the eastward flow through the Sarnia-Montreal 114 pipeline; and the decline i n eastern Canadian demand leads to a decline in imports and federal government subsidies, and to an improvement i n the o i l and gas trade accounts. A l l of the rent components are negative due to the production declines. The crude o i l producers are affected more than the natural gas producers for the same reason as given in experiment 1. In general, these s e n s i t i v i t y experiments indicate the pot e n t i a l l y large variation in the base case forecast due to changes in certain key exogenous variables. Another key exogenous variable which i s l i k e l y to have a wide range of uncertainty i s the price of foreign exchange, PFX, If the trade balance on the o i l and gas account i s at a l l r e a l i s t i c for the l a t e 1980's and 1990's (assuming PFX=1.0), then the variable PFX w i l l almost c e r t a i n l y depreciate. But the interactions surrounding the foreign exchange rate are complicated enough that I did not f e e l confident i n suggesting al t e r n a t i v e values. 115 6.4 An A n a l y s i s of Some Energy P r i c i n g P o l i c i e s I wish to use the model to examine the i m p l i c a t i o n s of v a r i o u s f e d e r a l government energy p r i c i n g p o l i c i e s . The d e s c r i p t i o n of these p r i c i n g p o l i c i e s are contained i n appendix 6.A, and the r e s u l t s i n appendix 6.B. The f i r s t p o l i c y option i s to c o n s t r a i n the n a t u r a l gas p r i c e to be lower than the base case p r i c e . The p o l i c y may be d e s i r a b l e because the s u b s t i t u t i o n away from crude o i l products towards n a t u r a l gas w i l l reduce the need to r e v e r s e the Montreal- S a r n i a p i p e l i n e a f t e r 1988, and w i l l hence reduce the d e f i c i t i n the balance of energy tr a d e , although It w i l l l e a d to an e a r l i e r i n d i c a t e d s t a r t - u p date f o r f r o n t i e r n a t u r a l gas. Indeed i t was s t a t e d , without evidence, i n the l a t e s t Department of Energy Mines and Resources r e p o r t [32] t h a t " s u b s t a n t i a l o p p o r t u n i t i e s e x i s t f o r reducing our f u t u r e o i l imports, through p o l i c i e s d i r e c t e d at ... encouraging the s u b s t i t u t i o n of domestic energy sources f o r imported o i l " [32, p.123]. S p e c i f i c a l l y , the n a t u r a l gas p r i c e i s c o n s t r a i n e d to be 85% of the ccmmodity-eguivalent Toronto c i t y - g a t e p r i c e (85% i s the a c t u a l r a t i o e x i s t i n g i n 1976). Before examining the d e t a i l e d outcome of t h i s experiment, one should glance at the second p a r t of Table 1 to o b t a i n an i d e a as t o the d i r e c t i o n and r e l a t i v e s i z e of the impact that the p r i c e shock w i l l have on the demand f o r the major primary f u e l s . The numbers recorded i n Table 1 i n d i c a t e that the own-price e l a s t i c i t y w i t h i n the complete model i s about -1.0. A l l c r o s s - p r i c e e l a s t i c i t i e s are p o s i t i v e , and a l l n e g l i g i b l e i n s i z e , except f o r c o a l . Hence the r e s u l t s of the p o l i c y 116 experiment should not exhibit much substitution of crude o i l products for natural gas, but should indicate a substantial increase in the demand for natural gas. The outcome of the experiment on the demands for the major primary fuels can be examined in Figure 6 as a s h i f t in the fuel shares and in Figure 7 as a s h i f t i n the demands. The results portrayed in the figures are consistent with the r e s u l t s reported i n Table 1. The share of crude o i l and e l e c t r i c i t y f a l l , and the share of natural gas r i s e s . The largest demand s h i f t i s through the own-price e f f e c t on natural gas. The shock minus control results are seen to reach t h e i r maximum ef f e c t after 1981, when the price d i f f e r e n t i a l reaches i t s maximum. The increased demand for natural gas leads to a two year e a r l i e r indicated start-up date for f r o n t i e r natural gas. When examining the production variables, one notices that they always reverse sign part way through the experiment. Since a fixed resource stock and a fixed rate of discovery i s assumed, any change i n the early years cf production must be followed by a change of opposite sign in the l a t e r years of production. The decline i n crude o i l demand leads to s l i g h t l y more western Canadian o i l being shipped eastward and s l i g h t l y lower imports. The rents to natural gas consumers increase s i g n i f i c a n t l y ; and the rents to natural gas producers decline somewhat; but o v e r a l l there i s a net benefit to Canadians, The second policy experiment involves r e s t r i c t i n g the wellhead price of crude o i l to 85% of i t s control value. The supposition behind t h i s experiment i s that the consuming provinces i n Canada would convince the federal government 1 1 7 continually to hold Canadian o i l prices below the world l e v e l . Since the transportation t a r i f f from the P r a i r i e s to Ontario i s not altered this implies that the Ontario crude o i l price f a l l s by s i g h t l y l e s s than 15%. Once again, the s h i f t s in f u e l demands look very s i m i l a r to those reported in Table 1. The negative value of OILPIPEM in 1974 indicates that desired increases in western Canadian crude o i l demand would have to be imported. However, from 1975 to 1981 the excess capacity i n o i l production i s s u f f i c i e n t to meet the increase i n demand without the need for imports into western Canada or a cut-back in the Sarnia-Montreal pipeline flow. The increased imports cause a f a i r l y substantial decline in the balance of energy trade. The rent to the crude o i l producers declines sharply, and the rent to Canadian consumers increases considerably. The substitution away from natural gas leads to a s l i g h t l y lower rent for natural gas producers. The very large rent increase to Canadian consumers of natural gas i s incorrect, and should be i g n o r e d . 3 9 The results of these experiments would vary considerably under any of the six s e n s i t i v i t y changes, I do not propose to test a l l of the combinations available. It i s possible to obtain some f e e l for a combination by examining the separate experiments. For instance, i f a pricing policy were to hold natural gas prices down by 15% under conditions of a 4.5% growth i n r e a l GNE then the r e s u l t s of policy experiment 1 would 3 9 This condition occurs because I shut o f f only part of the response which automatically adjusts the natural gas price to a Btu eguivalence with the new crude o i l price. The automatic response was shut off so that I could i s o l a t e the response to only the change i n the o i l price. 118 indicate an increase in demand for natural gas cf 10% and a decrease in the demand fox crude o i l of about 7.5%, 119 6.5 An Analysis of Some O i l and Gas Export P o l i c i e s The t h i r d and fourth policy experiments involve respectively reducing and increasing the exports of natural gas hy 101. Since none of the next six policy experiments af f e c t any of the demand variables, as can be seen by examining the OBTU variable, I have shortened the output of the r e s u l t s i n appendix 6.B. In the t h i r d policy experiment the only variables affected are natural gas production and taxable, income, the balance of trade, and the natural gas rents. The ef f e c t on each of these variables decreases over time, as the guantity of exports declines in the control solution. The corresponding variables in the two experiments are almost i d e n t i c a l in magnitude, but opposite in sign. A 10% increase in the exports of Canadian natural gas leads to an increase in t o t a l resource rents of about 3.4%, although only a 2.2% increase in the rants accrue to Canadians, The largest gainers are the producers who get an 8.5% increase and United States consumers who get a 5.3% increase. The rents to United States consumers increase because they receive more natural gas in the early years of the experiment when they pay less than the opportunity cost. The f i f t h and sixth policy experiments involve a l t e r i n g the export flow of crude o i l and a l t e r i n g the eastward flow through the Sarnia-Montreal pipeline. S p e c i f i c a l l y , the f i f t h policy experiment increases o i l exports by 250 Mbbl/d and sets the Sarnia-Montreal pipeline eastward flow to zero. The lack of excess o i l production capacity i n 1974 means that i n order to increase exports in 1974 by 250 Mbbl/d, i t was necessary to 120 increase imports into western Canada by 242 Mbbl/d. Since the Sarnia-Montreal pipeline flow i s only 100 Mbbl/d in 1976, the o i l production must be increased by 150 Mbbl/d to meet the increased expert requirement. From 1977 to 1984 the export-import swap can "easily be observed; imports have increased by 250 Mbbl/d, no o i l flows through the Sarnia-Montreal pipeline and no extra o i l production i s required. The increased o i l imports and experts lead to increases in both expert tax receipts and i n subsidy payments. Since the export tax receipts are greater than the subsidy payments, the balance of trade improves and the rent to the federal government increase s i g n i f i c a n t l y . The per unit expert tax i s greater than the subsidy because the export tax i s based on the price of offshore crude o i l shipped to the Chicago market. O i l imports increase by more than 250 Mbbl/d after 1984 because offshore o i l must be shipped into western Canada; and hence the balance of energy trade declines r e l a t i v e to the control value. In general, such a policy would lead to an increase in o v e r a l l rents to Canadians, with the major be n e f i c i a r i e s being the producers and the federal government. In the sixth policy experiment I attempt to explore the implications of reducing to zero the post-1975 exports of crude o i l and increasing the Sarnia-Montreal pipeline flow to 350 Hbbl/d after 1976. The decline in o i l production becomes smaller over time as the guantity of exports declines i n the control solution more than the increase in the pipeline flow; and from 1979 to 1983 the increase in o i l production becomes larger over time as the fixed increase in the pipeline flow becomes larger 121 than the continually declining exports in the control solution. The capacity constraint reached by 1984 causes the increased eastward flow cf 100 Mbbl/d to decline steadily. The balance of trade becomes more negative, and the export tax receipts drop more than the subsidy payments from 1976 to 1979 because the drop in exports i s larger than the increase i n import replacement. After 1979 the s i t u a t i o n reverses between the export and import replacement flows, and this leads to the balance of trade becoming more positive. The rent to producers declines by 16% because the large drop in o i l production in the early years more than of f s e t s the increased o i l production in l a t e r years. The large decline in the present value of 1.5 b i l l i o n 1976 d o l l a r s i n the federal government rent i s caused by the larger decline in export tax receipts than in subsidy payments. In general, with these trade p o l i c i e s that a l t e r production d i r e c t l y , any increase in production in the early years tends to lead to an increase in a l l rent components and the reverse for a decline in production in the early years. Since most of the federal rent i s derived from taxable production income, expert tax receipts, less import subsidy payments, the net federal t o t a l can vary considerably under these experiments. The r e l a t i v e change in exports and imports w i l l determine the e f f e c t on the balance of trade. Although the d i r e c t i o n of change i n production and the balance of trade i s clear in the natural gas p o l i c i e s i f i s s l i g h t l y more subtle in the crude o i l p o l i c i e s because of the simultaneous change in the import replacement f a c i l i t i e s of the Sarnia-Montreal pipeline. 122 6.6 An Analysis of Alternative .Montreal Pipeline Flows The l a s t two policy experiments measure the implications of alternative flows through the Sarnia-Montreal pipeline. The federal government policy with regard to the Sarnia-Montreal pi p e l i n e , as outlined in the Department of Energy Mines and Resources report, i s : Sel f - r e l i a n c e means reducing our v u l n e r a b i l i t y . It means supplying Canadian energy requirements from domestic resources to the greatest extent practicable,.. It recognizes, however, that the p o l i c i e s we w i l l adopt have costs as well as benefits and a balance that provides the maximum advantage to Canadians must he found (32, p. 124], Although I do not propose to discover a policy that provides •the maximum advantage to Canadians', I w i l l indicate two alt e r n a t i v e proposals. The seventh policy experiment assumes that the Sarnia-Montreal pipeline w i l l not be b u i l t u n t i l i t i s needed to import offshore o i l into Ontario. The accumulation of the o i l that i s not shipped eastward leads to a delay in the imports of o i l into Ontario from 1989 to 1990. The substantial drop in o i l production i s the cause of the large drop in rents to o i l producers. The 'shock minus control* values of OILPRO and OILPIPEM are i d e n t i c a l i n t h i s experiment, of course, the imports of o i l increase to the same extent that the flow through the Sarnia-Montreal pipeline decreases. I n i t i a l l y the balance of trade becomes more negative as the imports increase; but becomes more positive after 1989 when the production increases r e l a t i v e to the control value. The o v e r a l l rents to Canadians decline by about 8% with t h i s policy. From the pcint-of-view of the balance 123 of payments, the increase in the balance of trade In the 1990»s would c e r t a i n l y help to mitigate the large balance of trade d e f i c i t . The l a s t policy experiment assumes that the post-1976 flow through the Sarnia-Montreal pipeline w i l l be 350 Mbbl/d. In general, production increases u n t i l 1984, after which time the production gradually decreases. The pattern of the balance cf trade i s , guite naturally, opposite i n sign and smaller i n magnitude than the previous experiment. The production increase i n the early years of the experiment leads to a substantial increase in the rent to producers; but only a modest increase in the t o t a l rents to Canadians. Although these l a s t two experiments allow one to observe the response to a change in only one variable (CILPIPEM), I believe that i t i s more r e a l i s t i c to expect the pipeline flew to be altered in conjunction with the export flows, as i n experiments 5 and 6. For instance, when the exports are increased by 250 Mbbl/d at the same time as the eastward flow of the Sarnia-Montreal pipeline i s set to zero, the net benefit to Canadians increases by 3%, whereas with no change i n exports the net benefit to Canadians decreases by 8%. When the exports are set to zero at the same time as the eastward flow through the Sarnia-Montreal pipeline i s increased to 350 Mbbl/d, the net benefit to Canadians decreases by 3%, whereas with no change i n exports the net benefit to Canadians increases by 2%. 124 7, Summary In the l a t e s t documentation of government energy policy, An lH§I2J Strategy for Canada: P o l i c i e s for Self-Reliance [32], considerable emphasis i s placed on energy pr i c i n g p o l i c i e s ; and somewhat less emphasis i s placed on the new delivery c a p a b i l i t y of the Sarnia-Montreal o i l pipeline exfention. The strategy for o i l and gas prices are mentioned freguently, although the p r i c i n g policy toward natural gas i s more vague: for instance, i t i s stated that "future pricing p o l i c i e s for natural gas should r e f l e c t ... a relationship to the price cf o i l that i s appropriate in the l i g h t of the r e l a t i v e supplies of these energy sources and the desire to f a c i l i t a t e energy s e l f - r e l i a n c e through the encouragement of i n t s r f u e l substitution" [32, p.136]. A policy of using e l e c t r i c i t y prices "to encourage medium to long term substitution of e l e c t r i c a l energy for mere scarce forms" [32, p.129] i s not r e a l l y dealt with at a l l , probably because the federal government has l i t t l e control over the e l e c t r i c a l u t i l i t y companies. With regard to the Sarnia-Montreal pipeline policy, the federal government considers i t s existence to enhance the security of supply i n eastern Canada and to provide an acceptable degree of emergency preparedness. The major aim of t h i s thesis i s to provide an independent analysis cf the type of energy policy questions raised in the Department of Energy Mines and Resources report. The e f f e c t of the alternative p o l i c i e s w i l l , of course, depend upon the underlying state cf nature. Since there exists a considerable 125 degree of uncertainty about the future trend in a number of variables, I have provided the res u l t s of some s e n s i t i v i t y experiments. The Department of Energy Mines and Resources report also recognizes that "we are dealing in p r o b a b i l i t i e s , not c e r t a i n t i e s " [32, p.4] and hence enumerates a few key areas of uncertainty [32, p.3], and provides results of various scenarios, especially i n the chapter on demand. The potential importance of pricing p o l i c i e s on energy demand led to considerable e f f o r t being expended on specifying and estimating a demand system. The 'base-case' forecast of the demand model i s analysed in sections 2.4, 2.5, and 2.6. In general, the out-of-sample properties of the demand system indicate that i f performs rather poorly i n 1974, but reasonably well i n 1975 and 1976. The 'base-case' forecast for o i l and gas grows at a substantially lower rate than both the Department of Energy Mines and Resources and National Energy Board forecast during the 1976-1980 period, and grows at a s l i g h t l y higher rate thereafter. The response in the demand system due to price changes are reported in section 6.2, and summarized i n Table 1. The results of Table 1 indicate rather small cross price e l a s t i c i t i e s for crude o i l ; however, the cross price e l a s t i c i t i e s of natural gas with respect to e l e c t r i c i t y and crude o i l are comparatively large. The implication of the size of the cross price e l a s t i c i t i e s reported in Table 1 i s that any attempt at a pricing policy aimed at i n t e r f u e l substitution away from crude o i l i s going to f a i l . Of course, the own price e l a s t i c i t y of crude o i l i s large enough to f a c i l i t a t e a demand s h i f t away from crude o i l . In fact such a demand s h i f t would 126 probably occur i f the Canadian dollar were to depreciate due to a d e f i c i t i n the energy trade balance. A depreciation of the Canadian d o l l a r would cause a r i s e in the import price of crude o i l , which would in turn cause a r i s e in the Canadian wellhead price due to the assumption of eguating the domestic price with the foreign price (after 1S80). The re s u l t s cf the s e n s i t i v i t y and policy experiments are reported in sections 6.3, 6.4, 6.5 and 6.6. The s e n s i t i v i t y experiments indicate the possible existence of a f a i r l y wide range of outcomes from the demand system. The demand variables i n the energy pricing policy experiments indicate the same e l a s t i c i t i e s as reported in Table 1. However, through the use of the integrated energy model, the results of the energy pricing experiments trace out the f u l l conseguences. For instance, in the second policy experiment the i n e l a s t i c demand f o r crude o i l implies that net taxable income w i l l f a l l . However, i n the f i r s t policy experiment the net taxable income from natural qas f a l l s despite the fact that there i s a unitary demand e l a s t i c i t y for natural gas. This si t u a t i o n arises from the extra costs associated with increased production. A l l of the interactions a r i s i n g from a l t e r i n g export flows, and in some cases, a l t e r i n g i n conjunction the Sarnia-Montreal o i l pipeline flow are displayed in the rest of the policy experiments. In a l l of these experiments the gainers and losers can be i d e n t i f i e d by examining the rant variables. To properly assess the policy results of t h i s model, an answer must be given to the following question: how r e l i a b l e are the results? Naturally, t h i s i s a d i f f i c u l t guestion to answer. 127 I f e e l r e l a t i v e l y confident about the response of the demand' eguations. However, the system does have weaknesses: the dynamic response mechanism i s not derived t h e o r e t i c a l l y , the estimation parameters i n the expenditure share system for thermal e l e c t r i c i t y do not f i t too well, and the s p e c i f i c a t i o n of the t o t a l energy expenditure equation i s weak. Of course, the predicted levels of future demand are c r u c i a l l y dependent upon the assumptions for the exogenous variables. Despite these s h o r t f a l l s in the demand system, i t i s the supply side of the model which i s , I believe, less r e l i a b l e . The major areas of weakness in the supply models arise from the lack of behavioural assumptions regarding the exploration reserve additions and the costs of development and exploration. The gross reserve additions are exogenous, and the costs cf development and exploration are a function of the reserve additions; and hence they do net adjust during the policy experiments. Therefore the amount of new discoveries i s not related to price or cost. I w i l l conclude by stating what I believe to be the three main contributions of the dissertation. I believe that the s p e c i f i c a t i o n and estimation of the aggregate demand system i s a useful contribution. I believe that the process of building a model which integrates the petroleum supply and demand rela t i o n s h i p s , and d e t a i l s the costs, rents and trade flows has been successful, find I have been successful i n using the integrated energy system to generate guantitative results under alt e r n a t i v e p o l i c i e s . 128 FIGURE It CRNRD1RN ENERGY DEMRND DIVIDED BY REGION 3 = RTLRNTIC 2- 3 = QUEBEC 3- 2 = ONTRR30 4- 3 r PRR3R3E5 5- 4 - BC 5 ~ TOTRL ENERGY DEHRND FOR CRNRDR T T T ~1 1 1 1982 1984 1986 YERR5 T T 1 1 1 1992 1994 199S 1974 1976 1978 198D 1988 1990 129 FIGURE 2; SHRRES OF PRIMARY ENERGY FUELS DEHRNDED IN CRNRDR 1 = CRUDE OIL 2-1 = HRTURRL GfiS 3-2 - ELECTRICITY 4-3 ~ COfiL A 4. 4. 4 A 4. 4 4 4 4 4 4 4 4 4 4 4 4 4 4 / 1 4 3 — 3 — 3 — 3 — a 3 a . a q a q g q s a q q a q s q q b 2 — 2 — 2 — 2 — 2 — 2 — 2 2 2 2 2 2 2 2 2 ? ? . ? 9 9 ? 1974. 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 YEARS 130 FIGURE 3: CURRENT 4 EXPENDITURE ON ENERGY RCCUHULRTED BY REGION J = RTLRNTIC 2- 1 - QUEBEC 3- 2 - 0NTRR10 4- 3 = PRR3RIE5 5- 4 = BC 5 = TOTRL FOR CRNRDR 1 , 1 1 1 1 1 1 1 1 1 1 1974 I 976 197B 1980 1982 1984 I98S 1988 1990 1992 1994 199S YERRS 131 tn FIGURE 4s NRTURRL GRS DEMAND RND NON-FRONTIER PRODUCTION J-DOMESTIC DEMAND BRSED ON EQURTIDN5 EST3MRTED FOR TQTRL PR3MRRY ENERGY DEMAND RND ENERGY SHARES 2=DOMESTIC DEMAND + APPROVED EXPORTS 3- SUPPLY USING 1-.7300 FLOW RND 314 TCF ULT3HRTE RESERVES 4- RPPROVED EXPORTS 1974 1976 1978 1980 1 1932 1984 YERRS T T 1986 1988 1990 1992 1994 1996 132 a a UO. tn a FIGURE 5; CRUDE OIL DEM9ND. PRODUCT IGNM1BD FLOV THOUGH HGNTRERL PIPELlNtT^JFTOTBGUND) J-CRUDE OIL PRODUCTION CRPRCJTY 2- DES]RED PRODUCTION 3- VESTERN CRUDE OIL DEHRND APPROVED EXPORTS BrHONTRERL PIPELINE THROUGHPUT B-TOTRL CRNRDIRN DEMAND 1 1 r 1982 1984 1B8S YEARS r r 198a 1990 1992 1 1934 1996 133 FIGURE 6; SHARES OF PRIWRRY FUELS DEMANDED BEFORE FIND RFTER 152 FRLL FN PK BEFORE; 1 r CRUDE OIL 3-J r NATURAL G H s 5-3 r ELECTRICUY 7-5 = ffiRL o RFTER; 2 = CRUDE OIL 4-2 = NRTURRL GAS 6-4 = ELECTRICITY 7-6 r COAL --•7 7 7 7 7-7 7 7 in ^ A A 3 q ^ - 4 ^ - ^ - 4 i M 1 M M M o in in I N 7 7 7 7 7 7 7.7 7 .7 •fi~-E-.fi R R f i f i f i R R R R R ._R R R R R ft fi p T 7—2 T T 1974 1976 1978 1980 ~ l 1 1982 1584 YEARS T T 1986 1988 1990 1992 ~ l 1994 1 1996 134 FIGURE 7: BEFORE; a AFTER; in a a PRIMARY FUELS DEMANDED BEFORE AND BFTER I5X DROP 3N GR5 PRICE 1 = CRUDE OIL 3 = NATURAL GflS 5 = ELECTRICITY 2 = CRUDE OIL 4 ~ NATURAL GflS 6 = ELECTRICITY 8 a in a a in in CM a a. CM m r-. a o in. CD i n CM. • a •. n. 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"19697 £ 1 3 2 ] S t a t i s t i c s Canada, Crude Petroleum and Natural Gas Production, Monthly, Catalogue #26-006. £ 1 3 3 ] S t a t i s t i c s Canada, General Review of the Mineral §t rj.e s» Annual, Catalogue #26-201. £ 1 3 4 ] S t a t i s t i c s Canada, Coal Mijes, Annual, Catalogue #26-206. £ 1 3 5 ] S t a t i s t i c s Canada, Crude Petroleum and Natural Gas Industry, Annual, Catalogue #26-213. £ 1 3 6 ] S t a t i s t i c s Canada, Refined Petroleum Products, Monthly, Catalogue # 4 5 - 0 0 4 7 A n n u a l 7 Vol. 1 Catalogue # 4 5-204, 145 Vol. 2 Catalogue #45-208. £137] S t a t i s t i c s Canada, Petroleum Refiner ies, Catalogue #45-205. £138] S t a t i s t i c s Canada, O i l Pipe Line Transport, Annual, Catalogue #55-201; Monthly~Catalcgue #55-001, Catalogue #55-002. £139] S t a t i s t i c s Canada, Energy S t a t i s t i c s , Catalogue #57-002. £140] S t a t i s t i c s Canada, E l e c t r i c Power S t a t i s t i c s Vol 2, Annual, Catalogue~#57-202. £141] S t a t i s t i c s Canada, Gas U t i l i t i e s : Transport and Distribution System, Catalogue #57-2 05. £142] S t a t i s t i c s Canada, Detailed Energy Supply and Demand in Canada, Occasional, CataTogue"~#57-505; #57-207." £143] S t a t i s t i c s Canada, Exports by Commodity, Monthly, Catalogue #65-0047 £144] S t a t i s t i c s Canada, Imports b_y Commodity, Monthly, Catalogue #6 5-007. £145] S t a t i s t i c s Canada, Exports pyr Mode of Transport, Catalogue #65-206. £146] Turvey, R. and A.S. 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Crises: Impact of Canadian P o l i c i e s , United States Government Printing Of f i c e , 1974. £ 1 5 2 ] Vousden, N., "International Trade and Exhaustible 146 Resources: a Theoretical Model," International Economic Review, Feb. 1974, pp. 149-67. ~ ~ ~ [153] Watkins, G.C. and K. Sharp, "The Long Term Cost of Alberta Conventional Crude O i l , " The Journal of Canadian Petroleum Technology, January-March 1970. [154] Satkins, G.C, "A Note on the Economics of O i l Enhanced Recovery Projects," prepared for The V i c t o r i a Conference on Natural Resource Revenues, June 5-7,1975. [155] Waverman, L., "National Policy and Natural Gas: the Cost of a Border," The Canadian Journal of Economics, Aug. 1972. [156] Waverman, L. , Natural Gas and National Policy.: a Linear Programming Model of North American Natural Gas Flows, University of Toronto Press, 197 3. [157] Waverman, L., "The Reluctant Bride: Canadian and American Energy Relations," i n E.W. Erickson and L. Waverman (eds.), The Energy Question: an International Failure of P o l i c j , Vol. 2, University of Toronto Press, 1974?" [158] Waverman, L., "The Two Price System in Energy: Subsidies Forgotten," Canadian Public Policy, Winter 1975, pp. 76-88. £159] Waverman, L., "Energy in Canada: a Question of Rents," i n L. H. Officer and L.B. Smith (ed.) , Issues i n Canadian Econcmics, McGraw-Hill Ryerson Ltd., 1974. "~ 1 4 7 APPENDICES 1, L i s t of V a r i a b l e s , C o e f f i c i e n t s , and D e f i n i t i o n s This combined l i s t of v a r i a b l e s and c o e f f i c i e n t s has been compiled s e c t o r by s e c t o r f o r the t o t a l energy model. I t i s intended t o be used as an a i d to the reader i n i n t e r p r e t i n g the equations which s i m u l a t e Canada's v a r i o u s energy supply and demand components. In a l l t h e r e are four s e c t i o n s to t h i s l i s t . The f i r s t d e a l s with the demand model; the remaining three r e l a t e to the supply of energy, c o v e r i n g , r e s p e c t i v e l y , n o n - f r o n t i e r gas, n o n - f r o n t i e r o i l , and the l e s s f a c t o r s l i n k i n g recorded production and c i t y - g a t e d e l i v e r i e s of crude o i l , n a t u r a l gas, and e l e c t r i c i t y . 1.A Demand Sector 1. endogenous v a r i a b l e s name GFSUBC OBTU OBTU.AT OBTU. BC OBTU. C OBTU. G OBTU.L OBTU.C OBTU.CN OBTU. PH OBTU.QU PEN.AT PEN.BC PEN.ON PEN.PR PEN.QU PC. AT PC. BC PCCN PC. PE P C QU PG. BC PG.CN PG. PR PG. QU PL. AT d e s c r i p t i o n f e d e r a l government subsidy payments t o e a s t e r n consumers c f f o r e i g n crude o i l , m i l l i o n s of $ primary energy used i n Canada, t r i l l i o n s of output Btu primary energy used i n A t l a n t i c , t r i l l i o n s of output Btu primary energy used i n E . C , t r i l l i o n s c f output Btu t o t a l c o a l used i n Canada, t r i l l i o n s of output Btu t o t a l n a t u r a l gas used i n Canada, t r i l l i o n s of output Btu t o t a l e l e c t r i c i t y used i n Canada, t r i l l i o n s of output Btu t o t a l crude o i l used i n Canada, t r i l l i o n s c f output Btu primary energy used i n O n t a r i o , t r i l l i o n s of output Btu primary energy used i n P r a i r i e s , t r i l l i o n s of output Btu primary energy used i n Quebec, t r i l l i o n s of output Btu p r i c e index f o r primary energy i n A t l a n t i c , 1961=1.0 p r i c e index f o r primary energy i n B.C., 1961=1,0 p r i c e index f o r primary energy i n O n t a r i o , 1961=1.0 p r i c e index f o r primary energy i n P r a i r i e s , 1961=1.0 p r i c e index f o r primary energy i n Quebec, 1961=1.0 p r i c e of c o a l i n A t l a n t i c , $ / n i l l i o n output Btu p r i c e of c o a l i n B.C., $ / m i l l i o n output Btu p r i c e of c o a l i n O n t a r i o , $ / m i l l i o n output Btu p r i c e of c o a l i n P r a i r i e s , l / u i l l i o n output Btu p r i c e of c o a l i n Quebec, l / m i l l i o n output Btu p r i c e of n a t u r a l gas i n B.C., $ / m i l l i c n output Btu p r i c e of n a t u r a l gas i n O n t a r i o , $ / i r i l l i o n output Btu p r i c e of n a t u r a l gas i n P r a i r i e s , $ / m i l l i c n output Btu p r i c e of n a t u r a l gas i n Quebec, $ / m i l l i o n output Etu p r i c e of e l e c t r i c i t y i n A t l a n t i c , $ / m i l l i c n output Btu 148 PL. BC PL. CN PL. PE PL. QU PC. AT PO. BC PO. CN PG. PE PO. QO QCOAL QCL.AT QCL.BC QCL.CN QCL.PR QCL.QU QC, AT QC. BC QC.ON QC. PS QCQU QGAS QGL.BC QGL.CN QGL,PE QGL.QO QG. BC QG. ON QG. PE QG. QU QSLEC QL. AT QL. BC QL. CN QL. PR QL. QU QOIL QOILEAST p r i c e p r i c e p r i c e p r i c e p r i c e p r i c e p r i c e p r i c e p r i c e q u a n t i t y q u a n t i t y of of of of of of of of of e l e c t r i c i t y i n B.C., S / m i l l i c n output Btu e l e c t r i c i t y i n On t a r i o , $ / H i i l l i o n output Btu e l e c t r i c i t y i n P r a i r i e s , $ / m i l l i c n output Btu e l e c t r i c i t y i n Quebec, $ / m i l l i c n output Etu crude o i l i n A t l a n t i c , $ / m i l l i o n output Btu crude o i l i n B.C., $ / m i l l i o n output Btu crude o i l i n O n t a r i o , l / m i l l i o n output Btu crude o i l i n P r a i r i e s , $ / m i l l i o n output Btu crude o i l i n Quebec, $ / m i l l i c n output Btu of c o a l demanded i n Canada, m i l l i o n s of tons of c o a l used to generate thermal e l e c t r i c i t y i n A t l a n t i c , t r i l l i o n output Btu gu a n t i t y of c o a l used to generate thermal i n B.C., t r i l l i o n output Btu gu a n t i t y of c o a l used to generate thermal i n O n t a r i o , t r i l l i o n output Btu gu a n t i t y of c o a l used to generate thermal i n P r a i r i e s , t r i l l i o n output Btu gu a n t i t y of c o a l used to generate thermal i n Quebec, t r i l l i o n output Etu qu a n t i t y of c o a l demanded i n demanded demanded demanded demanded e l e c t r i c i t y e l e c t r i c i t y e l e c t r i c i t y e l e c t r i c i t y q u a n t i t y q u a n t i t y q u a n t i t y g u a n t i t y q u a n t i f y q u a n t i t y i n B.C., of of of of of of c o a l c o a l c o a l c o a l n a t u r a l n a t u r a l t r i l l i o n A t l a n t i c , t r i l l i o n output Btu E . C , t r i l l i o n output Btu Ont a r i o , t r i l l i o n output Btu P r a i r i e s , t r i l l i o n output Btu Quebec, t r i l l i o n output Btu gas demanded i n Canada, Bcf gas used to generate thermal e l e c t r i c i t y output Btu m i n i n i n thermal e l e c t r i c i t y thermal e l e c t r i c i t y thermal e l e c t r i c i t y q u a n t i t y of n a t u r a l gas used to generate i n O n t a r i o , t r i l l i o n output Btu qu a n t i t y of n a t u r a l qas used to generate i n P r a i r i e s , t r i l l i o n output Btu q u a n t i t y of n a t u r a l gas used to generate i n Quebec, t r i l l i o n output Etu q u a n t i t y of n a t u r a l gas demanded in B.C., t r i l l i o n output Btu gu a n t i t y of n a t u r a l gas demanded i n O n t a r i o , t r i l l i o n output Btu g u a n t i t y of n a t u r a l gas demanded i n P r a i r i e s , t r i l l i o n output Btu gu a n t i t y of n a t u r a l gas demanded i n Quebec, t r i l l i o n output Btu q u a n t i t y of e l e c t r i c i t y q u a n t i t y o f e l e c t r i c i t y t r i l l i o n output Btu gu a n t i t y of e l e c t r i c i t y t r i l l i o n output Btu q u a n t i t y of e l e c t r i c i t y demanded i n O n t a r i o , t r i l l i o n output Btu q u a n t i t y of e l e c t r i c i t y demanded i n P r a i r i e s , t r i l l i o n output Btu qu a n t i t y of e l e c t r i c i t y demanded i n Quebec, t r i l l i o n output Btu q u a n t i t y of crude o i l demanded i n Canada, m i l l i o n s of bbl q u a n t i t y of crude o i l demanded east o f the Ottawa v a l l e y , m i l l i o n s of bbl demanded demanded i n i n Canada, m i l l i o n s of Kwh A t l a n t i c , demanded in B.C. 149 QOILWEST quantity of crude o i l demanded west of the Ottawa valley, millions of bbl QOL.AT quantity of crude o i l used to generate thermal e l e c t r i c i t y i n A t l a n t i c , t r i l l i o n output Btu QOL.BC guantity of crude o i l used to generate thermal e l e c t r i c i t y in B.C., t r i l l i o n output Btu QOL.CN quantity of crude o i l used to generate thermal e l e c t r i c i t y in Ontario, t r i l l i o n output Btu QOL.PR guantity of crude o i l used to generate thermal e l e c t r i c i t y i n P r a i r i e s , t r i l l i o n output Btu QOL.QU quantity of crude o i l used to generate thermal e l e c t r i c i t y in Quebec, t r i l l i o n output Etu QO.AT guantity of crude o i l demanded in A t l a n t i c , t r i l l i o n output Btu QO.BC guantity of crude o i l demanded in B.C., t r i l l i o n output Btu QO.CN quantity of crude o i l demanded i n Ontario, t r i l l i o n output Btu QO.PR quantity of crude o i l demanded in P r a i r i e s , t r i l l i o n output Btu QO,QU quantity of crude o i l demanded In Quebec, t r i l l i o n output Btu QSL.AT quantity of thermal (secondary) e l e c t r i c i t y used i n A t l a n t i c , t r i l l i o n output Btu QSL.BC quantity of thermal (secondary) e l e c t r i c i t y used in B.C., t r i l l i o n output Btu QSL.CN quantity of thermal (secondary) e l e c t r i c i t y used in Ontario, t r i l l i o n output Btu QSL.PR quantity of thermal (secondary) e l e c t r i c i t y used i n P r a i r i e s , t r i l l i o n output Btu QSL.QU quantity of thermal (secondary) e l e c t r i c i t y used in Quebec, t r i l l i o n output Etu TEL$ t o t a l expenditure on fuels used for generating thermal e l e c t r i c i t y in Canada, millions of current $ T EL $AT t o t a l expenditure on fuels used for generating thermal e l e c t r i c i t y i n A t l a n t i c , millions of current $ TEL$BC t o t a l expenditure on fuels used for generating thermal e l e c t r i c i t y in B.C., millions of current $ TEL$0N t o t a l expenditure on fuels used for generating thermal e l e c t r i c i t y i n Ontario, millions of current $ I EL $ P R t o t a l expenditure on fuels used for generating thermal e l e c t r i c i t y in P r a i r i e s , millions of current $ TEL$QU t o t a l expenditure on fuels used for generating thermal e l e c t r i c i t y i n Quebec, millions of current $ T0TS1$ t o t a l expenditure or. thermal e l e c t r i c i t y in Canada, millions of $ TOTSL SAT t o t a l expenditure on thermal e l e c t r i c i t y i n A t l a n t i c , millions of $ T0TS1SBC t o t a l expenditure on thermal e l e c t r i c i t y in B.C., millions of $ T0TSL$0N t o t a l expenditure on thermal e l e c t r i c i t y in Ontario, millions of $ TOTSLSPB t o t a l expenditure on thermal e l e c t r i c i t y i n P r a i r i e s , millions of $ TOTSLSQU t o t a l expenditure on thermal e l e c t r i c i t y in Quebec, millions of $ 150 TOT$ t o t a l expenditure on primary energy fuels (excluding fuels used to generate thermal elec) in Canada, millions of $ T0T$AT t o t a l expenditure on primary energy fuels (excluding fuels used to generate thermal elec) in A t l a n t i c , millions of $ T0T$EC t o t a l expenditure on primary energy f u e l s (excluding fuels used to generate thermal elec) in B.C., millions of $ TOT$GN t o t a l expenditure on primary energy fuels (excluding fuels used to generate thermal elec) in Ontario, millions of $ I0T$PR t o t a l expenditure on primary energy f u e l s (excluding fuels used to generate thermal elec) in P r a i r i e s , millions of $ TOT$QU t o t a l expenditure cn primary energy fue l s (excluding fuels used to generate thermal elec) in Quebec, millions of $ 2, exogenous variables name description DPETEO demand for natural gas petrochemical feedstock GPM.BC natural gas d i s t r i b u t i o n pipeline miles i n B.C. GPM.ON natural gas d i s t r i b u t i o n pipeline miles in Ontario GPM.PR natural gas d i s t r i b u t i o n pipeline miles i n P r a i r i e s GPM.QU natural gas d i s t r i b u t i o n pipeline miles i n Quebec PCS.AT price of coal at the wellhead i n A t l a n t i c , $/ton PCW.PE price of coal at the wellhead i n P r a i r i e s , $/ton PCW.EC price of coal at the wellhead i n B.C., $/ton PCW.OS price of U.S. coal at Ontario border, $/tor. PFX price of foreign exchange, $ Canadian per $ U.S. PGNE price index for gross national expenditure, 1961=1.0 PGH.EC price of natural gas at the wellhead in B.C., $/Mcf PGS.PE price of natural gas at the wellhead in P r a i r i e s , $/Mcf PLE.AT price of e l e c t r i c i t y at the r e t a i l l e v e l in A t l a n t i c , ^/thousand Kwh PLR.BC price of e l e c t r i c i t y at the r e t a i l l e v e l in B.C., $/thousand Kwh PIE.ON price of e l e c t r i c i t y at the r e t a i l l e v e l in Ontario, $/thousand Kwh PIE.PR price of e l e c t r i c i t y at the r e t a i l l e v e l i n P r a i r i e s , $/thousand Kwh PLR.QU price of e l e c t r i c i t y at the r e t a i l l e v e l i n Quebec, $/thousand Kwh POW.PR price of crude o i l at the wellhead in P r a i r i e s , $/bbl PO.OFF price of offshore crude o i l , $/bbl QBL.AT guantity of hydro e l e c t r i c i t y i n A t l a n t t l c , t r i l l i o n s of output Btu QHL.BC guantity of hydro e l e c t r i c i t y i n B.C., t r i l l i o n s of output Btu QHL.CN guantity of hydro e l e c t r i c i t y in Ontario, t r i l l i o n s of output Btu QHL.PR guantity of hydro e l e c t r i c i t y i n P r a i r i e s , t r i l l i o n s of output Btu QHI.QU quantity of hydro e l e c t r i c i t y i n Quebec, t r i l l i o n s of output Btu QOILEEAT quantity of petroleum re-exports from A t l a n t i c , MKbbl QOILBEQU quantity of petroleum re-exports from Quebec, MMbbl UGNE r e a l Canadian gross national expenditure, millions of 1961 3. c o e f f i c i e n t s no. 1920 1921 1922 1923 1924 1925 1926 1927 192 8 1929 1 930 1 931 1 93 2 1 95 3 1 954 1 955 1 956 1 957 1 958 195 9 1960 1981 1982 1983 value .75 5. 803 3. 412 1.0 25.183 25.511 25.417 14.919 24.340 1.0 .607 .853 .767 .607 .796 .495 .543 .474 .315 .426 .814 .810 .798 .802 name PLCGNV IN/UN .0 IN/UN.L IN/UN.G IN/UN.C.AT IN/UN.C. QU IN/UK.C.ON IN/UN. C. PR IN/UN.C.BC OUT/IN.L OUT/IN. CAT OUT/IN.CQU OUT/ IN.CON OUT/IN.CPR OUT/IN. CEC OUT/IN.OAT OUT/IN.OQU OUT/IN.OON OUT/IN.OPR OUT/IN.0 EC OUT/IN.GQU OUT/IN.GON OUT/IN.GPR OUT/IN.GBC description factor used city-gate factor used to input factor used to input factor used to input factor used to input factor used to input factor used to input factor used to input factor used to input factor used to output factor used to output factor used to output factor used to output factor used to output factor used to output factor used to output factor used to output factor used to output factor used to output factor used to output factor used to output factor used to output factor used to output factor used to output to convert from r e t a i l to price for e l e c t r i c i t y to convert from natural units Btu for crude o i l to convert from natural units Etu units for e l e c t r i c i t y to convert from natural units Btu for natural gas to convert from natural units Btu for coal in At l a n t i c to convert from natural units Btu for coal in Quebec to convert from natural units Btu for coal in Ontario to convert from natural units Btu for coal in P r a i r i e s to convert from natural units Btu for coal i n B.C. to convert from input Btu Btu for e l e c t r i c i t y to convert from input Btu Btu for coal i n At l a n t i c to convert from input Btu Btu for coal in Quebec to convert from input Btu Btu for coal in Ontario to convert from input Btu Btu for coal in P r a i r i e s to convert from input Btu Btu for coal in B.C. to convert from input Btu Btu for crude o i l i n Atlantic to convert from input Btu Btu for crude o i l i n Quebec to convert from input Btu Btu for crude o i l in Ontario to convert from input Btu Btu for crude o i l i n P r a i r i e s to convert from input Btu Btu for crude o i l i n B.C. to convert from input Btu Btu for natural gas i n Quebec to convert from input Btu Btu for natural gas i n Ontario to convert from input Btu Btu for natural gas in Pr a i r i e s to convert from input Btu Btu for natural gas in E, C. 15; 1984 .86 1985 .87 1986 .85 1987 1988 1989 1990 1991 1992 199 3 1994 1995 1996 1 997 1998 1999 2000 2001 200 2 2003 2004 200 5 2006 2007 200 8 2009 2010 .686751 .987394 3.64228 .607893 .964029 .544603 1.60243 .470626 1.03761 .484769 OUT/IN.01 OUT/IN,CL OUT/IN. GL PCT.ft A PCT.AQ PCT.OSQ PCT.DSO PCT.PP PCT. DE-POT . PO EOT.PP POT.PE POT.EE PGT.PQ PGT.PO PGT.PP PGT.EE PC61.AT P061.AT PL61.AT PC61,QU P06T. QU PG61.QU PL61.QU PC61.CN P061.0N PG61.CN factor used to convert from input Btu to output Btu for crude o i l used in generating thermal e l e c t r i c i t y factor used to convert from input Btu to output Btu for coal used in generating thermal e l e c t r i c i t y factor used to convert from input Btu to output Btu for natural gas used in generating thermal e l e c t r i c i t y t a r i f f to transport coal within A t l a n t i c , $/ton t a r i f f to transport c o a l from A t l a n t i c to Quebec, $/ton t a r i f f to transport coal from U.S. to Quebec, $/ton t a r i f f to transport coal from U.S. to Ontario, $/ton t a r i f f to transport coal within P r a i r i e s , $/ton t a r i f f to transport coal within B.C., $/ton t a r i f f to transport cride o i l from P r a i r i e s to Ontario, $/bbl t a r i f f to transport crude o i l within P r a i r i e s , $/bbl t a r i f f to transport crude o i l from P r a i r i e s to B.C., $/bbl t a r i f f to transport crude o i l within B.C., $/bbl t a r i f f to transport natural gas from P r a i r i e s to Quebec, $/Hcf t a r i f f to transport natural gas from P r a i r i e s to Ontario, $/Mcf t a r i f f to transport natural gas within P r a i r i e s , $/Mcf t a r i f f to transport natural gas within B.C., $/Mcf price of coal i n At l a n t i c in 1961, $/million output Btu price of crude o i l in At l a n t i c in 1961, $/million output Btu price of e l e c t r i c i t y in A t l a n t i c in 1961, $/million output Btu price of coal i n Quebec in 1961, $/million output Btu price of crude o i l in Quebec i n 1961, $/million output Btu price of natural gas in Quebec in 1961 , $/million output Btu price of e l e c t r i c i t y in Quebec in 1961, $/million output Btu price of coal i n Ontario in 1961, $/million output Btu price of crude o i l in Ontario in 1961, $/million output Btu price of natural gas in Ontario in 1961, $/million output Btu 153 2011 1,94534 P161.CN 2012 .860738 EC61.PB 2013 1.20075 FC61.PR 2014 .186447 PG61.PR 2015 3.04001 PL61.FR 2016 ,751445 PC61.EC 2017 1.07553 P061.BC 2018 .249456 PG61.BC 2019 3.2SC60 PI61.BC 2020 .347 2021 2111 2040 .04 2041 .04 2042 ,04 2043 .04 2065 .04 2112 .045 2113 .04 2114 .08 2115 .04 2116 .03 2117 .04 2118 .20 2119 .15 2120 .04 2121 .36 2122 .10 2123 .04 2124 .02 2125 .04 2126 .02 2127 .02 2128 .03 2129 0. 1. 2130 0. 1. 2. price of e l e c t r i c i t y in Ontario in 1961, 3/millicn output Btu price of coal i n P r a i r i e s in 1961, $/millicn output Etu price of crude c i l in P r a i r i e s in 1961, l / m i l l i o n output Btu price of natural gas in P r a i r i e s in 1961, $/millIon output Btu price of e l e c t r i c i t y in P r a i r i e s in 1961, $/millicn output Btu price of coal i n B.C. i n 1961, $/Er.illion output Btu price of crude o i l in B.C. in 1961, $/million output Btu price of natural gas in B.C. in 1961, $/million output Btu price of e l e c t r i c i t y in B.C. in 1961, $/million output Btu share of Quebec coal imported from A t l a n t i c , average of 1969 to 1972 values f i r s t c o e f f i c i e n t from estimated eguations l a s t c o e f f i c i e n t from estimated eguations growth of coal demand i n Quebec after 1972 growth of coal demand i n Ontario after 1972 growth of coal demand in P r a i r i e s a f t e r 1972 growth cf coal demand i n B.C. after 1972 growth of coal demand i n A t l a n t i c after 1972 growth of r e a l Canadian GNE growth of price index f o r GNE growth of GPM.QU growth of GPM.ON growth of GPM.PR growth of GPM.BC growth of r e t a i l e l e c t r i c i t y prices a f t e r 1973 growth of r e t a i l e l e c t r i c i t y prices a f t e r 1976 growth cf r e t a i l e l e c t r i c i t y prices a f t e r 1980 growth of coal wellh3ad prices after 1973 growth of coal wellhead prices a f t e r 1976 growth of coal wellhead prices a f t e r 1980 growth of hydro generated elec in A t l a n t i c growth of hydro generated elec i n Quebec growth of hydro generated alec i n Ontario growth of hydro generated elec in P r a i r i e s growth of hydro generated elec i n B.C. Indicates that price cf crude o i l i n east i s based on foreign prices with nc subsidy Indicates that federal subsidy to eastern crude o i l consumers i s in ef f e c t •control' values for POW.PR, PGW.PR, PGW.BC and A (1941) are used in model Read in PCW.PR; PGW.PR, PGW.BC and A(1941) are set to 'control' value Read in PCW.PR; PGW.PR, PGW.BC are set to 'control' value; A(1941)=0 15t 3. Read in PGW.PR and PGW. EC; POW.PR and A (1941) are set to 'control' value 4. Read i n PGW.PR, PGW.BC, POW.PR ; A (1941) i s set to 'control' value 5. Read in PGW.PR, PGW.BC, POW.PR ; A(1941)=0.0 6 . Read in PCW.PR, A(1941) i s set to 'control' 213 1 0. Ose endogenous QGAS and QOIL in supply models 1. Use exogenous crude o i l demand series 2. Use exogenous natural gas demand series 2137 adjustment to offshore o i l price in GFSUBO 214 0 used to select a policy experiment 155 1.B Ncn-frentier Natural Gas Production 1. endogenous variables a l l variable names ending with $ are measured i n millions of current $ name description CAN.REQ, Canadian domestic demand, Tcf/yr DEFICIT excess of desired production over maximum, Bcf/d EXPORTS non-frontier gas exported, Tcf/yr GASACUM accumulated gas production i n non-frontier regions, i n Tcf GAS ABE non-frontier gas reserves coming into production, i n Tcf/yr GASADT t o t a l ncn-frontier gas discoveries from 1973, i n Tcf GASCCSTM marginal cost of non-frontier gas, i n 1976 cents/Mcf GASMAX available production frcm non-frontier reserves, in Bcf/d GASMAXA available production frcm non-frontier sources, Tcf/yr GASPLANT expenditure cn natural gas processing plants, m i l l i o n s 1961$ GASPEC production from non-frontier reserves, in Bcf/d KIDPNFS stock of non-frontier expenditure depletable for tax KRENTC1$ rents accruing to Canadian consumers of gas, millions $ KRENTC2I rents accruing to O.S. consumers of Canadian gas, millions $ KRENTGAS t o t a l rents accruing from natural gas production, millions $ KRENTNF$ rents to producers of ncn-frontier gas KRNFGFS rents accruing to federal government frcm non-frontier gas KRNFGPl rents accruing tc provincial government from gas PGASNF wellhead price of*non-frontier gas, i n cents/Mcf BEDPA rate of depletion allowance on non-frontier production RENTCANT t o t a l rents accruing to Canadians from f r o n t i e r and non-frontier qas and the Mackenzie Valley pipeline tfESEASE remaining stock of proven ncn-frontier reserves, both hooked-up and excess, in Tcf RESCOST cost of remaining stock of proven ncn-frontier reserves, in B i l l i o n s of 1<=61 $ RESDISCV discoveries of new reserves of non-frcntier gas, Tcf RESEXCES stock of excess reserves cf ncn-frontier gas, Tcf SUM desired Canadian production, Tcf/yr TCG AS NF corporation tax cn non-frontier gas production, millions $ IGASNFT taxable p r o f i t s from non-frontier gas production, millions $ 2, exogenous variables name description DEMAND Canadian domestic gas requirements, in Bcf/d DEMANDA optional series for overriding demand s e r i e s , Bcf/yr EGASD Mackenzie gas production at upper end of p i p e l i n e , Bcf/d EGASXD delta gas sold for export, proportion cf exports EXCAPGAS excess capacity in natural gas processing plants, Tcf EXGASNF non-frontier gas exported under approved contracts, Bcf/d GASCADJ estimation residuals for exploration and development costs GASLACJ estimation residuals for the land a c q u i s i t i o n c o e f f i c i e n t 156 GASMAX73 available production from pre-1972 hocked-up reserves, Bcf/d GASOPAEJ estimation residuals for operating expenditure c o e f f i c i e n t GASPLADJ estimation residuals for gas plant expenditure c o e f f i c i e n t GKAXA optional series for overriding GASMAX73 s e r i e s , Bcf/yr PEXOG price index equal to 2,11 in 1976, r i s i n g at 4% thereafter PEXPCBTG price of natural gas exported to the U.S., cenfs/Hcf PGAS value of gas i n central Canadian and D.S, market, cents/Mcf PGASBEG regulated price cf gas in central Canadian market, cents/Mcf 3. c o e f f i c i e n t s no. value 1860 1888 .43 1890 , 0744 1894 .0744 1895 .03 1901 42. 190 2 . 198 1904 • 2 5 1906 1907 1 90 8 1909 1910 .05 1911 1916 . 2624 1918 0.0 1919 114. 197 2 .04 2136 .655 2138 2139 2141 443. 1 gas production business basis description f r a c t i o n of commodity value paid for natural gas in Toronto marginal corporation income tax rate on average r e a l supply price of c a p i t a l to annual r e a l s o c i a l time preference rate average r e a l annual tax return on i n d u s t r i a l c a p i t a l delivery cost from Alberta border to Toronto, 1975 cents/Mcf puts c a p i t a l cost of new reserves on delivery royalty/wellhead price of non-frontier gas land a c q u i s i t i o n costs for non-frontier, 1961 cents/Mcf 1907 and 19C8 are c o e f f i c i e n t s in the cost function for discovery and development of new non-frontier reserves operating costs for gas production, 1961 cents/Mcf i n i t i a l gas flow as proportion of t o t a l recovery proportion of delta gas exported p r o v i n c i a l share of corporation tax on gas production i f >0 allows GASMAX73 to use a l l previous reserves t o t a l stock of recoverable ncn-frontier gas, Tcf the assumed rate of i n f l a t i o n f r a c t i o n of natural gas losses in excess of amount used to calculate marketable natural gas transport t a r i f f to border for gas exports, cents/Mcf transport t a r i f f to Chicago from border, cents/Mcf expenditure on natural gas plants, millions 1961$/Tcf 1 5 1 1.C Non-frontier Conventional Crude O i l Production 1. endogenous variables name description CPROSUM t o t a l production from o i l sands plants, Mbbl/d GFSOBO federal government subsidy payments to eastern consumers of foreign crude o i l , m illions of $ KOILEDPS stock of held over non-frontier depletable expenditure for taxation, millions of current $ KRENTOIL t o t a l rents accruing from o i l production, millions $ KR0ILC1$ rents accruing to Canadian consumers, millions $ KROILCAN t o t a l rents accruing to Canadians from ncn-frontier o i l production, millions $ KR0ILGF$ rents accruing to Canadian federal government from non-frentier o i l production, millions of current $ KROILGPI rents accruing to p r o v i n c i a l governments from non-frontier o i l production, millions of current $ KROILPS rents accruing to producers of ncn-frontier o i l , millions of current $ OILACOM accumulated o i l production in non-frontier regions, MMbbl OILADD o i l reserves that are hooked-up for production, MMbbl OILADT t o t a l discoveries of o i l from beginning of simulation, MMbbl OILCAND Canadian demand for crude o i l , Mbbl/d OILCCSTM marginal cost of non-frontier o i l , 1976 $/bbl OILDEF the d e f i c i t in o i l supply minus o i l demand, Mbbl/d OILIMFT imports of crude o i l , Mbbl/d OILLAG OILADD lagged nine years OILMAX available production from non-frontier reserves, Mbbl/d OILPIPEM throughput of Montreal pipeline, Mbbl/d {- i f westbound) OILPRC production demanded from non-frontier reserves, Mbbl/d QILRBASE remaining stock of proven non-frontier reserves, MMbbl OILRCOST cost of remaining stock of proven ncn-frontier reserves, millions of 1961 $ OILRDISC discoveries of new reserves of non-frontier o i l , MMbbl OILREDPA rate of avaiable depletion allowance on production OILREXES stock of excess reserves of ncn-frontier o i l , MMbbl OILSUM sum of Canadian demand and net exports, Mbbl/d OILXTCT crude o i l exports, Mbbl/d RTOILEXP tax rate on exports of crude o i l , $/bbl TCOILNF corporation tax cn o i l production, millions of current $ TXOIL federal government export tax revenue, millions current $ XBALGO$ current trade account balance for o i l and gas, millions $ XOILNFT taxable p r o f i t s from o i l production, millions of current $ 2. exogenous variables name EXCESS description excess production given past hooked-up reserves 15? GCOSPRO Great Canadian O i l Sands production, Mbbl/d OILCABJ estimation residuals for exploration and development costs GILEXPT non-frontier o i l exported, Mbbl/d OILLADJ estimation residuals for the land a c g u i s i t i o n c o e f f i c i e n t 0ILMAX74 production from pre-1974 hooked-up reserves, Mbbl/d OILOPACJ estimation residuals for operating expenditure c o e f f i c i e n t GILPROLD o i l production from pre-1973 hocked-up reserves PEXOG price index egual to 2.11 i n 1976, r i s i n g at 4% thereafter POILUS price of crude o i l in U.S. central market, $/bbl 3. c o e f f i c i e n t s no. value 1890 .07 44 1894 . 0744 1895 .03 1933 193 4 1935 1.74 1936 1937 19900. 1938 .55 194 0 .50 1941 250, 194 2 . 073 1 944 1945 .40 1946 .43 1947 .333 1 94 8 1949 .34 1950 , 10 1951 . 15 1952 .2624 description average r e a l supply price of c a p i t a l to business annual real s o c i a l time preference rate average r e a l annual tax return on i n d u s t r i a l c a p i t a l slope of cost function for discovery and development intercept of l i n e a r cost function c a p i t a l cost of new reserves on a delivery basis operating costs for o i l production, 1961$/bbl ultimate ncn-frontier o i l production, MMbbl transport cost from U.S. east coast to U.S. mid-west, 1973$/bbl transport cost from U.S. mid-west to p r a i r i e s , 1973$/bbl throughput of Montreal pipel i n e , Mbbl/d (+ i f eastbound) maximum o i l flow as proportion of t o t a l recovery land a c g u i i t i o n costs for non-frontier region, 1961$/bbl royalty/wellhead price on non-frontier o i l marginal corporate income tax rate on o i l production maximum rate of depletion allowance used to generate oilmax'k', where k i s c o e f f i c i e n t value used as c r i t i c a l r a t i o to test i f capacity increased used as c r i t i c a l r a t i o to test i f capacity increased capacity increase i n current period reserve addition p r o v i n c i a l share of corporation tax on o i l production 1.D Fuel Losses and Energy Supply Use 1, endogenous variables 15 S name description LGASBC natural gas losses and energy supply use in B.C., Bcf/yr LGASCN natural gas losses and energy supply use in Ontario, Bcf/yr LGASPB natural gas losses and energy supply use in P r a i r i e s , Bcf/yr LGASQ'U natural gas losses and energy supply use in Quebec, Bcf/yr LOSSGAS natural gas losses and energy supply use i n Canada, Bcf/yr L01LAT crude o i l losses and energy supply use in At l a n t i c , MMbbl/yr L0I1BC crude o i l losses and energy supply use in B.C., MMbbl/yr LOILCN crude o i l losses and energy supply use i n Ontario, MMbbl/yr LCILPE crude o i l losses and energy supply use in P r a i r i e s , MMbbl/yr LOILQU crude o i l losses and energy supply use i n Quebec, MMbbl/yr LOILEAST crude o i l losses and energy supply use east of the Ottawa valley l i n e , MMbbl/yr L0IL1EST crude o i l losses and energy supply use west of the Ottawa valley l i n e , MMbbl/yr LOSSL.AT e l e c t r i c i t y losses in A t l a n t i c , t r i l l i o n kwh LOSSL.BC e l e c t r i c i t y losses in B.C., t r i l l i o n kwh LOSSL.ON e l e c t r i c i t y losses i n Ontario, t r i l l i o n kwh LOSSL.PB e l e c t r i c i t y losses i n P r a i r i e s , t r i l l i o n kwh LOSSL.QU e l e c t r i c i t y losses i n Quebec, t r i l l i o n kwh 2. c o e f f i c i e n t s no. value description 2046 2047 2050 2056 2 057 2058 2059 2060 2 06 6 2069 2074 2133 2134 2135 .0487 .0804 .0889 .0883 . 0921 . 0929 .1416 . 0776 . 0985 .0500 -.0507 . 0566 . 1744 .2812 losses losses losses losses losses losses losses losses losses losses losses losses losses losses c o e f f i c i e n t c o e f f i c i e n t c o e f f i c i e n t c o e f f i c i e n t c o e f f i c i e n t c o e f f i c i e n t c o e f f i c i e n t c o e f f i c i e n t c o e f f i c i e n t c o e f f i c i e n t c o e f f i c i e n t c o e f f i c i e n t c o e f f i c i e n t c o e f f i c i e n t for crude o i l in for crude o i l in for crude o i l in for e l e c t r i c i t y for e l e c t r i c i t y for e l e c t r i c i t y for e l e c t r i c i t y for e l e c t r i c i t y for crude o i l in for crude o i l in for natural gas for natural gas for natural gas for natural gas Atla n t i c Quebec Ontario in A t l a n t i c in Quebec i n Ontario in P r a i r i e s i n B.C. P r a i r i e s B.C. in Quebec in Ontario in P r a i r i e s in B.C. 2. MODEL EQUATIONS 160 2.A DEMAND SECTOR DEMAND EQUATIONS FOR PRIMARY ENERGY PRODUCTS: GAS,OIL,ELECTRICITY AND COAL 1. EQUATIONS FOR ENDOGENOUS VARIABLES DEFINE THE PRICES PER MILLICN BTU FOR ALL OF THE FUELS IN EACH REGION PC.AT= (PCW. AT + PCT. AA)/(A (1924) *A (1930) ) PC.QU=(A{2020)*(PCW.AT+PCT.AQ) + (1.-A (2020) ) * (PC.US + PCT.USQ))/(A(1925) *A(1931)) PC. ON= (PC. US+PCT.USO) / (A (1926) *A (1 932) ) PC.PR=(PCW.PR + PCT.PP)/(A(1927)*A (1953)) PC. BC= (PCW. BC + PCT.BB) /(A (1928) *A (1954) ) PO.AT= (PO.OFF-. 1*(QO.QU/(QO.QU + QO. AT) ) ) / (A (1 92 1) *A (1955)) PO.QU= (PO.OFF-.1*(QO.QU/ (QO.QU+QO.AT)) +.1)/(A(1921)*A (1956)) THE ATLANTIC AND QUEBEC CRUDE OIL PRICE CAN BE SUBSIDIZED FROM 1974 IF A (2129) =1 AND NTIME>=74 THEN PO.AT= (POW.PR+POT. PO) / (A (1921) *A (1957) ) IF A(2129)=1 AND NTIME>=74 THEN PO.QU= (POW.PR + POT. PO)/ (A (1921) *A (1957) ) PO.ON= (POW.PR + POT. PO) / (A (1921) *A (1957) ) PO.PR= (POW. PR+POT.PP) /(A (1921) *A (1958) ) PO. BC= (PCW. PS+POT. PB) / (A (1921) *A (1959) ) PG.QU= (PGW. PR+PGT.PQ) /(A (1923) *A (1960) ) PG.ON= (PGW. PR+PGT.PO) / (A (19 23) *A (1 98 1) ) PG.PR= (PGW. PE + PGT.PP)/(A (1923) *A (1982) ) THE NATURAL GAS PRICE IN THE PRAIRIES IS DISCOUNTED FROM 1975 IF NTIME=75 THEN PG.PR=PG.PR*.97 IF NTIME=76 THEN PG . PR= PG. PR*. 75 IF NTIME=77 THEN PG.PR=PG.PR*.65 IF NTIME=78 THEN PG . PR=PG. PR*. 60 IF NTIME=79 THEN PG.PR=PG,PR*.57 IF NTIME>=80 THEN PG.PP=PG.PR*.55 PG.BC=(PGW.BC+PGT.BB)/ (A (1923)*A (198 3)) PL. AT= (A (1920) *PLR. AT) /A (1922) PL.QU= (A (1920) *PLR.QU) /A (1922) PL.ON= (A (1920) *PLR.ON) /A (192 2) PL. PR={A (1920) *PLR. PR) /A (1 922) PL.BC= (A (1920) *PLR.BC) /A (1922) THE VARIABLES REPRESENT THE CURRENT $ EXPENDITURE FOR ENERGY BY REGION T$AT=P0.AT*QO.AT+PL.AT*QL.AT T$QU=PO.QU*QC.QU+PG.QU*QG.QU+PL.QU*QL.QU T$ON=PO.CN*Q0.ON + PG.ON*QG.ON+PL.0N*QL. ON T$PR=PO.PR*QO^PR+PG.PR*QG.PR+PL.PR*QL.PR T$BC=PO.BC*QO.BC+PG.EC*QG.BC+PL.BC*QL.BC CALCULATE A PASCHE PRICE INDEX FOP ENERGY IN EACH REGION PEN.AT=T$AT/ (P061.AT*QO.AT + PL61.AT*QL.AT) PEN.QU=T$QU/(P061.QU*QO.QU+PG61.QU*QG.QU+PL61.QU*QL.QU) PEN.CN=T$CN/ (P061.0N*QO.CN + PG61.ON*QG. ON + PI61. CN*QL.ON) PEN.PR=T$FR/ (F061.PR*QO.PR + PG61.PR*QG.PS + PL61.PE*QL.PR) PEN.BC = T$BC/(P061.BC*QO.EC + PG61. BC*QG. BC + PL61.BC*QL.BC) CALCULATE THE CURRENT $ EXPENDITURE FOR ENERGY BY REGION AND FOR CANADA TOT$AT=PEN. AT*EXP (A (2021) + A (2072) *ALOG (UGNE) + A (2073)*ALOG (. 33333*PEN.AT/FGNE 11 +. 3 3 3 3 3 * J 1 L*P EM. AT/J 1 L* PGN E + . 3 33 3 3* J 2L * PEN . A T/J21, * PG N E) +TEMP (TOTSAT) ) TOT$QU=PEN. QU*EXP (A (20 2 2) +A (202 6) *ALOG (UGNE) + A (20 27) *^  ALOG (. 15*PEN.QU/PGNE+.35*J1L*PEN.QU/J1L*EGNE + . 35*J2L*PEN. QU/J2L*PGNE+. 15*J3L*PEN.QU/J3L*EGNE) + TEMP (TOTJQU) ) TOT$ON=PEN. ON*EXP (A (2023) + A (2026) *ALOG (UGNE) +A (2027) * ALOG (. 15*PEN.ON/PGNE+.35*J1L*PEN.ON/J1L*EGNE + .35*J2L*PEN.ON/J2L*PGNE+.15 *J3L*PEN,ON/J3L*PGNS) + TEME (TCT$ON) ) TOT$PR=FEN. PR*EXP (A (2024) +A (2026) * A LOG (UGNE) +A (2027) * ALOG(.15*PEN.PR/PGNE+.35*J11*P EN.P R/J1L* EG NE + .35*J2L*PEN.PB/J2L*PGNE+. 15*J3L*PEN.PE/J3L*EGNE) +TEHP (TCT$PE) ) TOT$BC=PEN. BC*EXP (A (2025) +A (2026) *ALOG (UGNE) +A (2027) * ALOG (. 15*PEN. BC/PGNE+. 35*J 1.L*PEN . BC/J1 L* EGNE +.35*J2L*PEN.BC/J2L*PGNE+.15*J3L*PEN.BC/J3L*EGNE) + TEMP (TOT$BC)) TOT$= (TOT$AT+TOT$QU+TOT$CN+TOT$PR+TOT$BC) CALCULATE THE MOVING WEIGHTED FUEL PBICES EY REGION JWPCAT=. 33333*PC.AT+, 33333*J1L*PC.AT+. 33333*J2L*PC.AT JWPOAT=,33 3 33*PO.AT+.3 3333*J1L*PG.AT+,33 33 3*J2L*PO.AT JWPOQU=.15*P0.QU+.35*J1L*P0. QU + .35*J2L*PO.QU + .15*J3I*PG.QU JWPOCN=.15*PO.ON+.35*J1L*P0.ON + .35*J2L*PO.ON + . 15*J 3L*PO.ON JWPOPB=.15*PO.PR+.35*J1L*P0.PR +.35*J2L*PO.PR + . 15*J3I*PC.PR JWPOBC=.15*PO.BC+.35*J1L*PO. DC + . 35*J2L*PO.BC +. 15*J3L*P0.BC JWPGQU=.15*PG.QO + .35*J1L*PG.QU + .35*J2L*PG.QU+. 15*J3L*PG.QU JWPG0N=.15*PG.ON+.35*J1L*PG.ON+.35*J2L*PG.ON+.15*J3L*PG.ON JWPGPR=„ 15*PG. PR + . 35*J1L*PG. PR + . 35*J2L*PG. PR +. 15*J3L*PG. PR JWPGBC=.15*PG.BC+.35*J1L*PG.BC + .35*J2L*PG.BC + . 15 *J 3L* PG.BC JWPLAT=. 33333*PL.AT+. 33333*J1L*PL.AT + . 33333*J2L*PL.AT JWPLQD=.15*P1.QU+.35*J1L*PL.Q0+.35*J2L*PL.QU+.15*J3L*PL.QU JWPLCN=. 15*PL.0N+.35*J1L*PL. ON + . 35 *J2L*PL. GN +. 15*J3L*PL.ON JWPLPE=.15*PL.PR + .35*J1L*PL. PR + . 35*J2L*PL.PR+.15*J3L*PL.PR JWPLBC=.15*PL.BC+,35 *J1L*PL.BC + .35*J2L*PL.BC + . 15*J3L*PL.BC CALCULATE THE QUANTITIES OF FUEL (IN TRILLION BTU) DEMANDED EY REGION QG.QU=TOT$QU/PG.QU* { A(2028) + A (204 4) *ALOG (JWPOQU) + A (20 61) * ALOG (J WPGQU) + A (2045) * ALOG (JWPLQU) +A (2054) *1E-5*GPM. QU +TEME (QG.QU)) QO.QU=TOT$QU/PO.QU*(A(20 32) + A (2048) * ALOG (JWPOQU) + A (2044) * ALCG (JWPGQU) + A (204 9) *ALOG (JWPLQU) +A (2055) *1E-5*GPM. QU + TEMP (QO.QU) ) QL.QU=TOT$QU/PL.QU*(A(2036) + A (20 51) *ALOG (JWPOQU) + A (20 52) * ALOG (JWPGQU) + A (205 3) *ALOG (JWPLQU) + A (20 62) * 1E-5*GPK. QU + TEME (QL. QU) ) IF NTIME>72 THEM QC.QU=(1.+A(2040) ) *J 1L*QC.QU QG.ON=TOT$ON/PG.ON*(A(2029) + A (2044) * ALOG (JWPOON) + A (20 61) * ALCG (JWPGON) + A (2045) * ALCG (JWPLCN) +A (2054) *1E-5*GEM.ON +TEMP (QG. ON) ) QO.ON=TOT$ON/PO. CN*(A(2033) + A (204 8) *ALCG (JWPCCN) + A (2044) * ALCG (JWPGCN) + A (2049) *ALOG (JWPLCN) + A (2055) *1E-5*GPM. ON + TEMF (QO.ON) ) Q L . O N = T O T $ O N / P L . C N * ( A ( 2 0 3 7 ) 1 6 2 + A ( 2 0 5 1 ) * A L C G ( J W P O O N ) + A ( 2 0 5 2 ) * A L C G ( J W P G O N ) + A ( 2 0 5 3 ) * A L O G ( J W P L C N ) + A ( 2 0 6 2 ) * 1 E - 5 * G P M . O N + T E M P ( Q L . O N ) ) I F N T I M E > 7 2 T H E N Q C . 0 N = ( 1 . +A ( 2 0 4 1 ) ) * J T L * Q C . 0 N Q G . P R = T O T $ P R / P G . P P * ( A ( 2 0 3 0 ) + A ( 2 0 4 4 ) * A L C G ( J W P O P E ) + A ( 2 0 6 1 ) * A L C G ( J W P G P P . ) + A ( 2 0 4 5 ) * A L C G ( J W P L P R ) + A ( 2 0 5 4 ) * 1 E - 5 * G P M . P R + T E H F ( Q G . P R ) ) Q O . P R = T O T $ P R / P O . P R * ( A ( 2 0 3 4 ) + A ( 2 0 4 8 ) * A L C G ( J W P O P R ) + A ( 2 0 4 4 ) * A L C G ( J W P G P R ) + A ( 2 0 4 9 ) * A L C G ( J W P L P R ) + A ( 2 0 5 5 ) * 1 E - 5 * G P H . P R +TEME ( C O . P R ) ) Q L . P E = T O T $ P R / P L . P R * ( A ( 2 0 3 8 ) + A ( 2 0 5 1 ) * A L OG ( J W P O P R ) + A ( 2 0 5 2 ) * A L C G ( J W P G P R ) + A ( 2 0 5 3 ) * A L O G ( J W P L P R ) + A ( 2 0 6 2 ) * 1 E - 5 * G P M . P R + TEME ( Q L . P R ) ) I F N T T M E > 7 2 T H E N Q C . P R = ( 1 . + A ( 2 0 4 2 ) ) * J 1 L * Q C . P R Q G . B C = T O T $ B C / P G . B C * ( A ( 2 0 3 1 ) + A ( 2 0 4 4 ) * A L O G ( J W P O B C ) + A ( 2 0 6 1 ) * A L C G ( J W P G B C ) + A ( 2 0 4 5 ) * A L C G ( J W P L B C ) + A ( 2 0 5 4 ) * 1 E - 5 * G P M . B C + T E M P ( Q G . B C ) ) Q 0 . B C = T 0 T $ B C / P 0 . B C * ( A ( 2 0 3 5 ) + A ( 2 0 4 8 ) * A L O G ( J W P O B C ) + A ( 2 0 4 4 ) * A L O G ( J W P G B C ) + A ( 2 0 4 9 ) * A L O G ( J W P L B C ) + A ( 2 0 5 5 ) * 1 E - 5 * G P M . B C + T E M P ( C O . B C ) ) Q L . B C = T O T $ B C / P L . E C * ( A ( 2 0 3 9 ) + A ( 2 0 5 1 ) * A L O G ( J W P O B C ) + A ( 2 0 5 2 ) * A L O G ( J W P G B C ) + A ( 2 0 5 3 ) * A L O G ( J W P L B C ) + A ( 2 0 6 2 ) * 1 E - 5 * G P M . B C + T E M E ( Q L . B C ) ) I F N T I M E > 7 2 T H E N Q C . B C = ( 1 . + A ( 2 0 4 3 ) ) * J 1 L * Q C . B C Q O . A T = T O T $ A T / P O . A T * ( A ( 2 0 6 3 ) + A ( 2 0 6 7 ) * A L O G ( J W P O A T ) + A ( 2 0 6 8 ) * A L O G ( J W P L A T ) + T E M P ( Q O . A T ) ) Q L . A T = T O T S A T / P L . A T * ( A ( 2 0 6 4 ) + A ( 2 0 7 0 ) * A L O G ( J W P O A T ) + A ( 2 0 7 1 ) * A L C G ( J W P L A T ) + T E M F ( Q L . A T ) ) I F N T I M E > 7 2 T H E N Q C . A T = ( 1 , + A ( 2 0 6 5 ) ) * J 1 L * Q C . A T C A L C U L A T E T H E Q U A N T I T Y O F S E C O N D A R Y E L E C T R I C I T Y D E M A N D E D A S A R E S I D U A L Q S L . A T - Q L . A T + A ( 1 9 2 2 ) * L O S S L . A T - Q H L . A T I F Q S L . A T < = 0 . 0 T H E N Q S L . A T = 1 . O E - 3 0 Q S L . Q U = Q L . Q U + A ( 1 9 2 2 ) * L O S S L , Q U - Q H L . Q U I F Q S L . Q U < = 0 . 0 T H E N Q S L , Q U = 1 . O E - 3 0 Q S L . O N = Q L . O N + A ( 1 9 2 2 ) + L O S S L . O N - Q H L . O N I F Q S L . C N < = 0 . 0 T H E N Q S L . O N = 1 . O E - 3 0 Q S L . P R = Q L . P R + A ( 1 9 2 2 ) * L O S S L . P R - Q H L . P R I F Q S L . P R < = 0 . 0 T H E N Q S L . P R = 1 . O E - 3 0 Q S L . B C = Q L . B C + A ( 1 9 2 2 ) * L O S S L . B C - Q H L . B C I F Q S L , B C < = 0 . 0 T H E N Q S L * B C = 1 . O E - 3 0 C A L C U L A T E T H E C U R R E N T $ E X P E N D I T U R E ( M I L L I O N S ) F O R T H E R M A L E L E C T R I C I T Y T O T S L $ A T = P L , A T * Q S L . A T T O T S L $ Q U = P L . Q U * Q S L . Q U T O T S L $ O N = P L . O N * Q S L . O N T O T S L $ P R = F L . P P * Q S L . P R T O T S L $ E C = P L . B C * Q S L . B C T O T S L $ = ( T O T S L $ A T + T O T S L $ Q U + T O T S L $ C N + T O T S L $ P R + T O T S L $ B C ) C A L C U L A T E T H E C U R R E N T $ E X P E N D I T U R E F O R F U E L S T O G E N E R A T E E L E C T R I C I T Y 163 TEL$AT=.000001*EXP(A (2075) + A (2080) *ALOG(1000000.*TOTSL$AT) + TEMP (TEL$AT)) TEL$QD=. 000001*EXP (A (20 76) + A (20 8 0) * ALOG (1 0 00 00 0 . *TOTSL$QU) + TEMP (TELSQU) ) TEL$CN=.000001*EXP (A (2077) +A (208 0) *ALOG (1 00000 0. *TOTSL$ON) + TEMP (TEL$ON) ) TEL$PR=. 00000 1*EXP (A (207 8) + A (2080) * ALOG (10 00 000. *TOTSL$PR) +TEMP (TEL$PR) ) TEL$BC=.000001*EXP (A (207 9)+A (2 080) *ALOG(10 00000.*TOTSL$BC) • TEMP (TEL$BC) ) TEL$= (TEL$AT+TEL$QU+TEL$0 N+TEL$PR + TEL$BC) CALCULATE THE FUEL PRICES IN $ PER MILLION OUTPUT BTU PC LA T= PC. AT* (A (19 30) / A (1985) ) PCLQU=PC. QU* (A (1 9 31) / A (1985) ) PCLON=PC.CN* (A (1932) / A (1985) ) PC LP R= PC. PR* (A (1953) / A (1985) ) POLAT=PO, AT* (A (1955) /A (1984) ) P0LQU=PC.QU*(A(1956)/A(1984)) POLCN=PC.CN* (A (1957) / A (1984) ) POLPE=PO.PR* (A (1958) /A (1984) ) POLBC=PO.BC* (A(1959)/A (1984) ) PGLQU=PG. QU* (A (1960) / A (1 986) ) PGLON=PG.CN* (A (1981) /A (1986) ) PGLPR=PG.PR*(A(1982)/A(1986) ) PGLBC=PG.BC* (A (1983) / A (1986) ) CALCULATE THE QUANTITY OF FUELS USED IN GENERATING THERMAL ELECTRICITY QGL.QU=0.0 QOL.QU=TEL$QU/POLQU* (A (2084)+A (2100)*ALOG(PCLQU) + A (2101) * ALCG (POIQU) +TEMP (QOL. QU) ) QCL. QU=TEL$QU/PCLQU* (A (2087) +A (2103) *ALOG (PCLQU) + A (2104) *ALOG (POLQU) +TEBP (QCL. QU) ) QGL. ON=TEL$CN/PGLON* (A (2082) +A (2090) *ALOG (PCLON) + A (2091) * ALOG (POLON) + A (2092) *ALOG (PGLON) +TEMP (QGL.ON) ) QOL.ON=TEL$CN/POLON* (A(2085) +A (2093) *ALOG (PCLON) + A (2094) *ALCG (POLON) +A(2095) *ALOG (PGLON) +TEMP (QOL. ON)) QCL. ON=TEL$CN/PCLCN* (A (2088) + A (209 6) *ALOG (PCLON) + A (2097) *ALOG (POLON) +A (2098) *ALOG (PGLON) +TEMP (QCL.ON) ) QGL. PR=TEL$PR/PGLPR* (A(2083) +A (2090) *ALOG (PCIPB) +A (2091) *ALOG (FOLPR) +A (2092) *ALOG (PGLPR) +TEMP (QGL. PR) ) QOL. PB=TEL$PR/POLPR* (A (2086) +A (2093) * ALOG (PCLPB) + A (2094) *ALCG (POLPR) + A (20 9 5) *ALOG (PGLPR) +TEMP (QOL. PR) ) QCL. PR=TEL$PB/PCLPR* (A (2089) +A (2096) * ALOG (PCLPR) + A (2097) * ALCG (POLPR) +A (2098) *ALOG (PGLPR) +TEMP (QCL. PR) ) QOL. AT=TEL$AT/POLAT* (A (2099) +A (2100) *ALOG (PCLAT) +A (2101) *AL0G (POLAT) +TEMP (QOL. AT) ) QCL. AT=TEL$ AT/PCL AT* (A (2102) +A (2103) * ALOG (PCLAT) +A (2104) * A LOG (POLAT) +TEMP (QCL. AT) ) QGL. BC=TEL$BC/PGLBC* (A (2107) +A (2111) *ALOG (POLBC) + A (2110) *ALOG (PGLBC) + A (210 8) *ALCG (GPM. BC)+TEMP (QGL. BC) ) QOL. EC=TEL$BC/POLBC* (A (2105) +A (2109) * A LOG (POLBC) + A (211 1) * ALOG (PGLBC) + A (2106) * A LOG (GPM. BC) +TEMF (QOL. BC) ) TABULATE THE TOTAL OUTPUT BTU DEMANDED FOR EACH REGION AND FOR CANADA OBTU.AT= (QC.AT + QO.AT+QL.AT) OBTU.QU= (QC.QU+QO.QU + QG.QU+QL.QU) OBTU.ON= (QC.ON+QO.ON + QG.CN + QL.ON) OBTU.PR= (QC.PB + QO.PR + QG.PE + QL. PR) OBTU.BC= (QC. BC + QO. BC+QG. BC + QL. BC) OBTU= (OBTU. AT + OBTU. QU + OBTU. ON+OBTU.PR+CBTO.BC) 164 TABULATE THE TOTAL OUTPUT BTU DEMANDED FOR EACH FUEL ACROSS ALL REGIONS OBTU.C=(QC.AT+QC.QU+QC.ON+QC.PR+QC.BC +QCL.AT+QCL.QU+QCL.ON+QCL,PR) OBTU.O=(QO.AT+QO.QU+QO.ON+QO.PR+QO.BC +QOL.AT+QOL.QU+QOL.CN+QCL.FF+QGL.BC) OBTU.G=(QG.QU+QG.ON+QG.PR+QG.BC+QGL.QU +QGL,CN+QGL.PR+QGL.BC) OBTU.L=(QL.AT+QL.QU+QL.ON+QL.PR+QL.BC) CALCULATE THE QUANTITIES OF EACH FUEL DEMANDED IM NATURAL UNITS QUANTITY OF COAL DEMANDED IN MILLIONS CF TCNS QCOAL= (QC. AT/ (A (1930) * A (1924) ) +QC.QU/{A (1931) *A (1925) ) + QC,ON/ (A(1932)*A(1926))+QC.PR/(A(1953) *A(1927)) + QC. BC/ (A (1954) *A (1928) ) +QCL. AT/ (A (1985) *A (1924) ) + QCL. QU/ (A (1985) *A (1925)) +QCL.ON/ (A (1985) * A (1926) ) +QCL. PR/ (A (1985) *A (1927) ) ) QUANTITY OF NATURAL GAS DEMANDED IN BCF QGAS= (QG. QU/(A(1960) *A (1923) ) +QG.ON/ (A (1981) *A (1923) ) +QG.PR/(A (1982) *A (1 92 3) ) +QG. BC/(A(1983) *A (1923)) +QGL. QU/ (A (1986) * A (19 23)) + QGL.ON/(A (1986)*A (19 23)) +QGL.PR/ (A (1986) *A (1923) )+QGL.BC/(A(1986)* A(1923))) +DPETRC QUANTITY OF ELECTRICITY DEMANDED IN MILLIONS OF KWH QELEC=1000.* (QL. AT/A (1922) +QL.QU/A (1922) +QL. ON/A (1922) + QI.PR/A(1922)+QL. BC/A(1922)) >~ QUANTITY OF CRUDE OIL DEMANDED IN THE EAST, WEST AND CANADA IN MILLIONS BBL QOILEAST= (QO. AT/(A(1955) *A(1921) ) +QO.QU/(A (1 956) *A (1921) ) + QOL.AT/(A(1984)* A(1921))+QOL.QU/(A(1984) * A(1921)) ) QOILWEST= (QO.ON/(A (1 957) *A(1921) ) +QO.PR/(A ( 1 9 5 8 ) *A ( 1 9 2 1 ) ) +QO.BC/ (A (1959) *A (192 1) )+QOL.ON/(A (1 984) *A (1921) ) +QOL.PR/(A (1984) *A (1921) ) + QOL. BC/(A (1984) * A (1921) ) ) QOIL=QOILEAST+QOILWEST CALCULATE THE SUBSIDY PAYMENTS MADE TO EASTERN OIL CONSUMERS QOILAT=QO. AT/ (A (1955) * A ( 1 9 2 1 ) ) +QOL. AT/ (A (1 984) *A (1 921) ) +QOILREAT Q0ILQU=QC.QU/(A(1956) *A (1921) ) +Q0L. QU/ (A (1984) *A (1921) ) +QOILREQU GFSUEO=QOILAT*(PC.OFF+A (2137)-.1*{Q0.QU/(QO. QU+QO.AT)) -(EOW.PR+POT.PO)) + (Q0ILQU-. 365*A (1941) ) * (PC.OFF+A (213 7) -. 1* (QO. QU/ (QO. QU+QO. AT) ) +. 1 -(PCW.PR+POT.PO)) +LOILEAST*(PO.OFF+A(2137)-(POW.PR + POT.PO)) IF NTIME<=73 THEN GFSUBO=0.0 IF GFSUBC<0.0' THEN GFSUBO=0.0 DEMAND FOR PRIMARY ENERGY PRODUCTS: GAS,OIL,ELECTRICITY AND COAL 2. EQUATIONS FOR EXOGENOUS VARIABLES 165 SET TRANSPORTATION COEFFICIENTS FOR ALL FUELS IF NTIME=69 THEN PCT.AA=1.90 IF NTIMS=70 THEN PCT.AA=1.61 IF NTIME-=71 THEN PCT.AA=2.50 IF NTIME>=73 THEN PCT.AA=2.50*PEXOG/1.56 PCT. AQ=3. 20 IF NTIHE>=73 THEN PCT.AQ=3.20*PEXOG/1.56 PCT.USQ=4.70 IF NTIME>=73 THEN PCT.USQ=4.70*PEXOG/1. 56 PCT.USO=3.50 IF KTIME>=73 THEN PCT.USO=3.50*PEXOG/1.56 PCT.PP=4.20 IF NTIME>=73 THEN PCT.PP = 4.20*PEXOG/1.56 IF NTIME=69 THEN PCT.EB=5.03 IF NTIME=70 THEN PCT.BB=3.96 IF NTIME=71 THEN PCT.BB=3.60 IF NTIME>=73 THEN PCT.EE=3.60*PEXOG/1.56 P0T.P0=.51 IF NTIME>75 THEN POT.PO=.51*(PEXOG/1.95) POT.PP=.10 IF NTIME>75 THEN POT.PP=.10* (PEXOG/1.95) POT.PB=.40 IF NTIME>75 THEN POT.PB=.4 0*(PEXOG/1.95) POT.BB=.59 IF NTIME>75 THEN POT.BB=.59* (PEXOG/1. 95) PGT.PO=.30 IF NTIME=73 THEN PGT.PO=.35 IF UTIME>=74 THEN PGT.PC= 1. 16*.01*A (1901) *(PEXCG/1.95) PGT.PQ=.36 IF NTIME>=73 THEN PGT.PQ=PGT.PO+.06*PEXOG/1.95 PGT.PP=.04 IF NTIME>75 THEN PGT.PP=.04*(PEXOG/1.95) PGT.BB=.12 IF NTIME>=73 THEN PGT.BB=.20 IF NTIME>75 THEN PGT.BB=.20* (PEXOG/1.95) DECREASE GROWTH IN GAS DISTRIBUTION PIPELINE MILES IF NTIME>=83 THEN A (2114) = . 75*A (2114) IF NTIME>=81 THEN A (2115) =. 75*A (211 5) IF NTIME>=83 THEN A (21 16) = . 75*A (2 11 6) IF NTIME>=83 THEN A (21 1 7) =. 75 * A (2 11 7) SET UGNE AND PGNE TF NTIME=75 THEN UGNE-IF NTIME>75 THEN UGNE: IF NTIME>81 THEN UGNE= IF NTIME = 75 THEN PGNE-IF NTIME=76 THEN PGNE-IF NTIME=77 THEN PGNE: IF NTIME>77 THEN PGNE-=J1L*UGNE* (1.002) = J1L*UGNE* (1.054) = J1L*UGNE* (1 . + A (2112) ) -J1L*PGNE*1.1017 = J1L*PGNE*1. 082 = J1L*PGNE*1. 06 =J1L*PGNE* (1. + A(2113)) DETERMINE THE GAS DISTRIBUTION PIPELINE MILES IF NTIME>74 THEN GPM.QU=JlL*GPM.QU* (1.+A (2114)) IF NTIME>74 THEN GPM. 0 N=J1 L*GPM .ON* (1 . + A (21 1 5) ) IF NTIME>74 THEN GPM.PB=J1L*GPH.PP* (1.+A (2116)) IF NTIME>74 THEN GPM.BC=J1L*G PM.BC* (1.+A (2117)) DETERMINE THE VALUES IF NTIME>73 THEN IF NTIME>76 THEN IF NTIME>80 THEN IF NTIME>73 THEN IF NTIME>76 THEN IF NTIME>80 THEN IF NTIME>73 THEN IF NTIME>76 THEN IF NTIME>80 THEN IF NTIME>73 THEN IF NTIME>76 THEN IF NTIME>80 THEN IF NTIME>73 THEN IF NTIME>76 THEN IF NTIME>80 THEN RHINE THE COAL P IF NTIME>73 THEN IF NTIME>76 THEN IF NTIME>80 THEN IF NTIME>73 THEN IF NTIME>76 THEN IF NTIME>80 THEN IF NTIME>73 THEN IF NTIME>76 THEN IF NTIME>80 THEN IF NTIME>73 THEN IF NTIME>76 THEN IF NTIME>80 THEN FOR THE RETAIL PRICE CF ELECTRICITY PLR.AT=J1L*PLR.AT* (1.30) PLR.AT-J1L*PLR.AT* (1. + A(2119) PLR.AT=J1L*PLR.AT* (1. + A (2120) PLR.0U=J1L*PLR.QU* (1, + A(2118) PLR.QU=J1L*PLR.QU*(1,+A (2119) PLR.QD=J1L*PLR.QU* (1, + A(2120) PLR.ON=J1L*PLR.ON* (1 , + A (21 18) PLR.0E=J1L*PLR.0N* (1,+A (2119) PLR.ON=J1L*PLR.ON* (1.+A (2120) PLR.PE=J1L*PLR.PE* (1.+A (2118) PLR.PR=J1L*PLR.PR* (1.+A (21 19) PLR.PR=J1L*PLR.PR* (1.+A (2120) PLR.BC=J1L*PLR.BC* (1 ,+ A(21 18) PLR.BC=J1L*PLR.BC* (1. + A (2119) PLR.BC-J1L*PLR.BC* (1.+A (2120) ICES AT THE WELLHEAD AND THE US IMPORT PRICE PCW. AT=J1L*PCW.AT*(1.+A(2121) PCW.AT=J1L*PCW.AT* (1.+A (2122) PCW. AT=J1L*P,CW.AT* (1 , + A (2123) PCW. PR=J1L*PCW.PR* (1. 62) PCW.PR=J1L*PCW.PR* (1,+A (2122) PCW.PR=J1L*PCW.PR*(1,+A(2123) PCW. BC=J1L*PCW, BC* (1 . 52) PCW.BC=J1L*PCW.BC*(1,+A(2122) PCW.BC=J1L*PCW.BC*(1.+A(2123) PC.US=J1L*PC.US*(1.+A(2121) ) PC.US=J1L*PC.US*(1.+A(2122) ) PC.US=J1L*PC.US*(1. +A(2123)) 166 DETERMINE THE LANDED IF NTIME=75 THEN NTIME=76 THEN NTIME=76 THEN NTIME>76 THEN • A (2130) =6 THEN A (2130) >=4 THEN IF IF IF IF IF IF PRICE OF OFFSHORE CRUDE OIL PO. OFF=PFX*A (1 974) A(1974)=13.00 PO.OFF=PFX*A (1974) PO. OFF=PFX#J 1 L*PO. OFF* (1. +A (1 972) ) * (1, GO TO 11 GO TC 20 + A (1973) ) A(2130)=1 OR A(2130)=2 THEN GO TO 10 DETERMINE THE WELLHEAD PRICE OF CRUDE CIL IN PRAIRIES IF NTI.HE=75 THEN POW,PR=7.25 POW.PR=8.53 POW.PR=10.25 POW.PR=11.75 POW.PR=13.25 PCW.PR=PO.OFF-POT.PC 10 IF A (2130) =3 THEN GO TO 20 IF NTIME=76 THEN IF NTTME=77 THEN IF NTIME=78 THEN IF NTIME=79 THEN IF NTIME>=80 THEN  DETERMINE. THE WELLHEAD PRICE OF NATURAL GAS IN PRAIRIES AND BC 1 1 20 IF NTIME>=76 THEN IF NT.IME>=74 THEN IF A (2130) =6 THEN IF NTIME=75 THEN IF NTIME=76 THEN IF NTIME>76 THEN IF NTIME>78 THEN IF NTIMF>80 THEN PGASREG=100.*A(1860)*(PGW.PR+POT,PO)/A(1921) PGW.PR=.01*PGASREG-PGT.PO GO TO 20 PGW.BC=.255 PGW.BC=J1L*PGW.BC*1.40 PGW.BC=J1L*PGW.BC*1.20 PGW.BC=J1L*PGW.BC*1.15 PGW.BC=J1L*PGW.BC*(1.06) IF A(2130)=2 OR A{2130)=5 THEN A(1941)=0.0 DETERMINE THE QUANTITE5 OF HYDRO ELECTRICITY AVAILABLE IN EACH REGION IF NTIME>74 THEN IF NTIME>74 THEN IF NTIME>74 THEN IF NTTME>74 THEN IF NTIME>74 THEN QHL.AT=J1L*QHL.AT*(1.+A(2124) ) QHL.QU=J1L*QHL,QU*(1 , + A (21 25) ) QHL.0N-J1L*QHL.0N* (1 . +A (21 26) ) QHL.PR = J1L*QHL.PR* (1.+A (2127)) QHL.BC = J1L*QHL.BC* (1.+A (2128)) ALLOW FOR SHIFT IN BC AND PRAIRIES. AWAY FROM DIESEL FUEL IF NTIME>73 THEN A(1958)= A(1958)* (.47/A (1 958))**.2 IF NTIME>73 THEN A (1959) =A (1959) * (. 47/A (1959) ) **. 2 ALLOW FOR EXTRA SUBSIDY PAYMENTS FROM 1976 TO 1980 IF NTIME=75 THEN A(2137)=.45 IF NTIME>=76 THEN A (21 37) =. 30* (PO. OFF-POW. PR-POT. PO)/U. 00 168 3. THE FOLLOWING ARE THE 'TEMP' ADJUSTMENTS TO THE ESTIMATED EQUATIONS IF NTIME=69 THEN TSMP(QG.QU)=+.00499 IF NTIME=70 THEN TEMP (QG.QU)= + .00192 IF NTIME=71 THEN TEMP(QG.QU)=+.000185 IF NTIME=72 THEN TEMP (QG.QU)=-.00 108 IF NTIME>=73 THEN TEMP (QG.QU)=-.000628 IF NTIME>=74 THEN TEMP (QG.QU)=0.0 IF NTIME>=75 THEN TEMP (QG. QU) =+. 005+. 01 * ( 1.-1 ./EXP ( (NTIME-75)/4 .) ) IF NTIME=69 THEN TEMP(QO.QU)= -.0277 IF NTIME=70 THEN TEMP (QC.QU)=-.0343 IF NTIME=71 THEN TEMP(QC.QU)= +.00882 IF NTIME = 72 THEN TE MP (QC. QU) = +. 0311 IF NTIME>=73 THEN TEMP (QO.QU)=+.0549 IF NTIME>=74 THEN TEMP (QC. QU) =+. 11 IF NTIME>=75 THEN TEMP (QO.QU)=+.095-. 0"*(1.-1./EXP((NTIME-75)/4.)) IF NTIME=69 THEN TEMP (QL. QU) = + . 0227 IF NTIME=70 THEN TEMP (QL.QU)= + . 0324 IF NTIME=71 THEN TEMP (QL.QU)= 00900 IF NTIME=72 THEN TEMP(QL.QU)=0301 IF NTIME>=73 THEN TEMP (QL. QU) =-.0542 IF NTIME>=74 THEN TEMP (QL. QU) =-. 1 1 IF NT.IME>=75 THEN TEMP (QL.QU) =-« 10+. 03* (1 .-1. /EXP ( (NTIME-75) /4. ) ) IF NTIME=69 THEN TEMP (QG. ON) = + . 00603 IF NTIME=70 THEN TEHP (QG.OU) =+ .0110 IF NTIME=71 THEN TEMP (QG. ON) = + . 00981 IF NTIME=72 THEN TE MP (QG. ON) =+. 0 1 37 IF NTIME>=73 THEN TEMP (QG.ON)=+.0115 IF NTIME>=74 THEN TEMP (QG.ON) = + .03 IF NTIME=69 THEN TEMP (QO.ON)=-.0128 IF NTIME=70 THEN TEMP (QO.ON)=-. 0205 IF NTIME=71 THEN TEMP (QO.ON)=-. 0228 IF NTIME=72 THEN TEMP (QG.ON)=-. 0320 I F NTIME>=73 THEN TEMP (QO.ON)=-,0110 IF NTIME>=74 THEN TEMP (QO. ON) = + . 03 IF NTIME=69 THEN TEMP (QL.ON)- + .00678 IF NTIME=70 THEN TE MP (QL. ON) = + . 00 951 IF NTIME=71 THEN TEMP (QL.ON)= + .0130 IF NTIME=72 THEN TE MP (QL. ON) = + . 01 83 IF NTIME>=73 THEN TEMP(QL.ON)=-.000510 IF NIIME>=74 THEN TEMP (QL. CN) = -. 06 IF NTIME=69 THEN TEMP (QG.PR)= + . 00309 IF NTIME=70 THEN TEMP (QG. PR) =-. 00708 IF NTIME=71 THEN TEMP(QG.PR)=-.0101 IF NTIME=72 THEN TEMP (QG. PR) = -. 01 02 IF NTIME>=73 THEN TEMP (QG.PR)=-.0354 IF NTIME>=74 THEN TEMP (QG.PR)= + .01 IF NTIME=69 THEN TEMP (QC.PR)=-. 0303 IF NTIME=70 THEN TEMP (QO. PR) =-. 0332 IF NTTME=71 THEN TEMP ( Q C . P R ) 0 2 1 3 IF NTIME=72 THEN TEMP (QC.PR)=-.0215 IF NTIME>=73 THEN TEMP (QO.PR)=+.0197 IF NTTME>=74 THEN TEMP(QC. PR) =0.04 IF NTIME=69 THEN TEMP(QL.PR)=+.0272 IF NTIME=70 THEN TEMP (QL.PR)= + . 0403 IF NTIME=71 THEN TEMP(QL.PR)=+.0314 IF NTIME=72 THEN TEMP (QL. PR) =+ . 03 17 IF NTIME>=73 THEN TEMP (QL.PR)=+.0157 IF NTIME>=74 THEN TEMP (QL.PR)=-,05 IF NTIME=69 THEN TEMP(QG.BC)=+.00583 IF NTIME=70 THEN TEMP (QG. BC) = + .00148 IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTTME=70 THEN IF 'NTIME = 71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTIME=70'THEN IF NTIME=71 THEN IF NTIME>=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTIKE=70 THEN IF NTIME=71 THEN IF NTIME>=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME=69 THEN IF NTIME-70 THEN IF NTIME=71 THEN IF NTTME-72 THEN IF NTIME>=73 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN 169 TEMP (QG. BC) = +. 00488 TEMP (QG. BC) = + . 00339 TEMP (QG. BC) =+.0163 TEMP (QG. BC) = + . 02 TEMP (QO.BC)=-,0202 TEMP (QC. BC) = + . 00280 TEMP (QC. BC) = -. 0112 TEMP (QC. BC) = -. 000254 TEMP (QO.BC)=+.0280 TEMP (QO. BC) =+.04 TEMP (QL. BC) = + .01 44 TEMP (QL. BC) =-. 00428 TEMP (QL. BC) = + . 00634 TEMP (QL. BC) =-. 00314 TEMP (QL. BC) =-.0443 TEMP (QL. BC)=-.06 TEMP(Q0.AT)=-. 0477 TEMP (QC. AT) --. 0733 TEMP (QC. AT) = + .0175 TEMP (QO. AT) = + . 0625 TEMP (QO. AT) =+.10 TEMP (QO. AT) = + .14 TEMP (QL. AT) = + . 0477 TEMP (QL. AT) = +. 0733 TEMP(QL,AT)=-.0175 TEMP (QL. AT) =-.0625 TEMP (QL. AT) =-.10 TEMP (QL. AT)=-. 14 TEMP (QGL.ON)=-.0153 TEMP (QGL. ON) =-.0300 TEMP(QGL.ON)=-.0 04 61 TEMP (QGL. ON) = + . 1 14 TEMP (QGL.ON)= + . 151 TEMP (QCL. CN) =+.0365 TEMP(QCL,ON)=+.0137 TEMP (QCL. ON) =+.00001 52 TEMP(QCL,ON)=-,0166 TEMP (QCL. CN) = +. 00 47 2 TEMP (QCL, ON) =-.0212 TEMP (QCL.ON)=+.0163 TEMP(QCL.ON)=+.004 60 TEMP (QCL. CN) =-.0978 TEMP (QCL.ON)=-. 156 TEMP (QGL. PO) = + .0123 TEMP (QGL.PE)=-.0409 TEMP (QGL, PR) =-. 0 887 TEMP (QGL. PR) =-. 1 03 TEMP (QGL. PR) = -. 08 59 TEMP (QGL.PR)=-. 02 TEMP (QCL. PR) =-.000 362 TEMP (QCL. PR) =-.0265 TEMP (QCL.PR)=-.0439 TEMP (QCL. PR) =-.0545 TEMP (QCL. FR) =-. 0275 TEMP(QOL.PR)= + . 01 TEMP (QCL. PR) =-.0119 TEMP (QCL. PR) = + .0675 TEMP (QCL. PR) = + . 133 TEMP (QCL, PR) = + .158 TEMP (QCL. PR) = +. 113 IF NTIME>=74 THEN TEMP (QCL. PR) = + .01 i ; IF NTIME=69 THEN TEMP (QCL.AT)=+.0658 IF NTIME=70 THEN TEMP (QCL.AT)= + .182 IF NTIME=71 THEN TEMP (QOL,AT) = +.158 IF NTIME=72 THEN TEMP(QCL.AT)=+.198 IF NTIME>=73 THEN TEMP (QOL. AT) "= + . 250 IF NTIME = 69 THEN TEMP (QCL. AT) =-. 0658 IF NTIME=70 THEN TEMP(QCL.AT)--.182 IF NTT ME=7 1 THEN TE MP (QCL. AT) = -.158 IF NTIME=72 THEN TEMP(QCL.AT)=-.198 IF NTIME>=73 THEN TEMP (QCL.AT) = -.2 50 IF NTIME=69 THEN TEMP (QOL.QU)=+.0927 IF NTIME=70 THEN TEMP(QGL.QU)=+.0634 IF NTIME=71 THEN TEMP(QCL,QU)=+.0359 IF NTIME=72 THEN TEMP(QCL.QU)=+.112 IF NTIME>=73 THEN TEMP (QOL.QU)= + . 110 IF NTIME>=74 THEN TEMP (QOL.QU)=0.05 IF NTIME=69 THEN TEMP (QCL.QU)=-.0927 IF NTIME=70 THEN TEMP (QCL. QU) =-. 0634 IF NTIME=71 THEN TEMP (QCL.QU)=-.0359 IF NTIME=72 THEN TEMP (QCL.QU)112 IF NTIME>=73 THEN TEMP (QCL. QU) =-.110 IF NTIME>=74 THEN TEMP (QCL.QU) = -.05 IF NTIME=69 THEN TEMP (QOL.BC)=-.0139 IF NTIME=70 THEN TEMP (QCL. BC) •=-. 041 8 IF NTIME=71 THEN TEMP(QCL.BC)=+.208 IF NTIME=72 THEN TEMP(QCL. BC)= +.112 IF NTIME>=73 THEN TEMP (QOL.BC)=-. 116 IF NTIME = 69 THEN TEMP (QGL.BC)= + .0139 IF NTIME=70 THEN TEMP(QGL.BC)=+.0418 IF NTIME=71 THEN TEMP (QGL.BC)=-.208 IF NTIME=72 THEN TEMP (QGL.BC)=-.112 IF NTIME>=73 THEN TEMP (QGL. BC) = +. 116 IF NTIME=69 THEN TEMP(TEL$AT)=-.109 IF NTIME=70 THEN TEMP(TELSAT) =-.0513 IF NTIME=71 THEN TEMP(TEL$AT)= + .070 1 IF NTIME>=72 THEN TEMP(TEL$AT)=+.141 IF NTIME>=73 THEN TEMP(TEL$AT)=+.231 IF NTIME=69 THEN TEMP (TEL$QU) =-. 274 IF NTIME=70 THEN TE MP(TEL$QU)=-.277 IF NTIME=71 THEN TEMP (TEL$QU)=-.121 IF NTIME=72 THEN TEMP(TEL$QU)=+.0845 IF NTIME>=73 THEN TEMP (TEL$QU)= + .212 IF NTIME=69 THEN TEMP(TEL$ON)=-,111 IF NTIME=70 THEN TEMP(TEL$ON)=+.0000153 IF NTIME=71 THEN TEMP(TEL$0N)=-.0109 IF NTIME=72 THEN TEMP(TELJON)=+.0125 IF NTIME>=73 THEN TEMP(TEL$ON)=+.0396 IF NTIME=69 THEN TEMP (TEL$PR)=-.0396 IF NTIME=70 THEN TEMP(TEL$PR)=+.0634 IF NTIME=71 THEN TEMP(TEL$PR)=+.195 IF NTIME=72 THEN TEMP(TEL$PR)=+.261 IF NTIME>=73 THEN TEMP (TEL$PR) =+. 290 IF NTIME>=75 THEN TEMP (TEL $ PR) = + . 290-. 17* (1 .-1. /EXP ( (NTIME-75) /5.) ) IF NTIME=69 THEN TEMP(TEL$BC)=+.0262 IF NTIME=70 THEN TEMP(TEL$BC)=-.00542 IF NTIME=71 THEN TEMP (TELSBC)=+,144 IF NTIME=72 THEN TEMP (TEL$BC)=+.201 IF NTIME>=73 THEN TEMP (TEL$BC)= + .236 IF NTIME>=75 THEN TEMP (TEL$BC)=+ . 236-.13* (1 .- 1./EXP( (NTIME-75)/5.)) IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME>=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME>=75 THEN IF NTIME>=76 THEN IF NTIME>=77 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME>=75 THEN IF NTIME>=76 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME>=75 THEN IF NTIME>=76 THEN IF NTIME=69 THEN IF NTTME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF HTTME>=75 THEN IF NTIME>=76 THEN IF NTTME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME>=75 THEN IF NTIME>=76 THEN TEMP (T G T $ A T)=-.0585 TEMP (TCT$AT) =-.0573 TEMP (TGT$AT)=+.0508 TEMP (T0T$AT) = +. 138 TEMP (TOT$AT)= + . 22 TEMP (TOTSAT)= + .30 TEMP (TOT$AT) = +. 33 TEMP (TOT$AT) = + . 37 TEMP (T0T$AT) = + .42 TEMP (T0T$QU)=-.0483 TEMP (TCT$QU)= + .0154 TEMP (TCT$QU) =-.0148 TEMP (T0T$QU)=+.00112 TEMP (TOT$QU) = + . 00 56 6 TEMP (TCT$QU) = +. 09 TEMP (TOT$QU)= + . 13 TEMP (TOT$QU)=+. 14 TEMP (TCT$ON) = + .0 0078 5 TEMP (TCT$ON) =+.0 382 TEMP(TOT$ON)=-.0 0026 8 TEMP (TOT$ON)-+.0165 TEMP (TOT$ON)= + .0166 TEMP (TOT$ON) = +. 03 TEMP (TOT$ON) = +. 06 TEMP (TOT$ON) = + .14 TEMP (T0T$PR) = + . 0 0296 TEMP(TCT$PR) =-.0 000544 TEMP(TGT$PR)=-.0 08 76 TEMP (TCT$PR)= + .00912 TEMP(TOT$PR)=+.00455 TEMP (TCT$PR) = + . 05 TEMP (TOT$PR) = + . 09 TEMP (T0T$PR)= + . 12 TEMP(TGT$BC)=+.0219 TEMP (T0T$BC) =-.0264 TEMP (TCT$BC) = + . 0 04 47 TEMP (T0T$BC) = + .0 08 82 TEMP (TOT$BC)=+.00496 TEMP (TOT$BC) = + . 05 TEMP (TOT.SBC) = + . 07 TEMP (TOT$BC)= + . 12 THE FOLLOWING ARE THE 'TEMP' ADJUSTMENTS TO THE LOSSES EQUATIONS IF NTIME= 69 THEN TEMP (LOILAT)=- .698 IF NTIME= 70 THEN TEMP (LGILAT) = + .990 IF MTIME= 71 THEN TEMP(LOILAT)=+.?57 IF NTIME= 72 THEN TEMP (LGILAT)=- 1. 26 IF NTIME> = 73 THEN TEMP (LOILAT) = -. 123 IF NTIME> = 74 THEN TEMP (LGILAT) = 0.0 IF NTIME= 69 THEN TEMP (LCSSL. AT) =-.0764 IF NTIME= 70 THEN TEMP (LCSSL.AT) =+.0595 IF NTIME= 71 THEN TEMP (LOSSL. AT) =-.0799 IF NTIME= 72 THEN TEMP (LCSSL. AT) =+.0425 IF NTIME> = 73 THEN TEMP (LOSSL.AT) = + .100 IF NTIME= 69 THEN TEMP (LCILQU) = + 2. 21 IF NTIME-70 THEN TEMP (LCILQU) = + .696 IF NTIME= 71 THEN TEMP (LCILQU) =-. 0392 IF NTIME= 72 THEN TEMP (LCILQU)=- .872 IF NTIME> = 73 THEN TEMP (LOILQU) = -. 261 IF NTIME> = 74 THEN TEMP (LCILQU) = 0. 0 IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTTME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIWE>=73 THEN IF NTIME=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTIME-=70 THEN IF NTIME=71 THEN IF NTIME=72 THEN IF NTIME>=73 THEN IF NTIME>=74 THEN IF NTIME=69 THEN IF NTIME=70 THEN TEMP (LGASQU)=+.276 TEMP (LGASQU) =-.330 TEMP(LGASQU)=-.902 TEMP (LGASQU)=+.548 TEMP (LGASQU) = -. 391 TEMP(LGASQU)=0.0 TEMP (LOSSL. QU) =-. 340 TEMP (LOSSL.QU) =-.231 TEMP (LOSSL. QU) = + .361 TEMP(LCSSL.QU) =-.350 TEMP (LOSSL. QU) = + . 177 TEMP (LCILON)=-3.36 TEMP (LOILON)=+.754 TEMP (LCILON) = + 1. 86 TE MP (LCILON) =-1.60 TEMP (LOILCN) = -. 0826 TEMP (LOILON) =0. 0 TEMP (LGASON) = + .808 TEMP(LGASON)=+2.48 TEMP (LGASON)=-.841 TEMP (LGASON) =-2. 91 TEMP (LGASON) = -4. 29 TEMP (LGASON) =0. 0 TEMP (LOSSL.ON)=-.230 TEMP (LOSSL.ON)=-.0195 TEMP (LCSSL. ON) =-.213 TEMP(LOSSL.ON)=+.495 TEMP (LOSSL.CN)=-.408 TEMP (LOSSL.ON)=0.0 TEMP (LCILPR)=-.150 TEMP (LCILPR) =-1. 04 TEMP (LOILPR) =+1. 25 TEMP (LCILPR) =-2. 14 TEMP (LCILPR) =-. 387 TEMP (LCILPR) = 0. 0 TEMP(LGASPR)=-11.7 TEMP (LGASPR) = + 14.2 TEMP(LGASPR)=-21.1 TEMP (LGASPR) =-2. 75 TEMP (LGASPR) = +9.47 TEMP (LGASPR) = 0. 0 TEMP (LCSSL.PR)=-.153 TEMP (LCSSL. PR) =+.158 TEMP(LOSSL.PR)=-.0390 TEMP (LCSSL. PR) =+.0304 TEMP(LOSSL.PR)=+.00554 TEMP (LCILBC) =-.167 TEMP(LCILBC)=-.551 TEMP(LCILBC)=+1.22 TEMP (LOILBC)=-1. 12 TEMP (LOILBC)=-.597 TEMP (LCILBC) =0. 0 TEMP(LGASBC)=+28.3 TEMP(LGASBC)=+33.3 TEMP(LGASBC)=+16.1 TEMP(LGASBC)=-19.6 TEMP(LGASBC)=-21.4 TEMP (LGASBC) = 0. 0 TEMP(LOSSL.BC)=-.119 TEMP(LCSSL.BC)=+.175 IF NTIME=71 THEN TEMP (LCSSL.DC)=-.360 IF NTIME=72 THEN TEMP (LCSSL.BC)=+.423 IF STIME>=73 THEN TEMP (LCSSL. EC) = + . 41 6 IF NTIME> = 75 THEN TEMP (LOILEAST)=10. IF NTIME=74 THEN TEMP (LCILWEST)=+19.6 IF NTIME=75 THEN TEMP (LCILWEST)= + 26. IF NTIME>=76 THEN TEMP(LOILWEST)=0.0 P?X IS DEFINED TC BE 1.0 DURING CONTROL PFX=1.0 DPETPO SERIES CONTINUES AT ITS 1996 VALUE IF NTIME>95 THEN DPETRO=J1L*DPETRO SET THE NATURAL GAS COMMODITY DISCCUNT FACTOR A (1860) = .85+.03* (NTIMS-76) IF A(1860)>=1.0 THEN A(1860)=1.0 SET THE AMOUNT OF RE-EXPORTS OF PETROLEUM FRODUCTS IN ATLANTIC AND OUEBEC IF NTIME=73 THEN QOILREAT=18.524 IF NTIME>=74 THEN QOILREAT=27.552 IF NTIME=73 THEN QOILREQU=14.715 IF NTIME>=74 THEN QOILREQU=4.272 SET THE GROWTH IN QUEBEC HYDRO ELECTRICITY IF NTIME>=75 THEN A(2125) = 0. IF NTIME>=78 THEN A (2125)=.04 2.B NON FRONTIER NATURAL GAS PRODUCTION SECTOR 174 1. EQUATIONS FOR ENDOGENOUS VARIABLES SET THE NOMINAL DISCCUNT RATE STP1=1. + A (1890) * ( (1. +A (1890) ) **. 5) STP2=1.+A (1890) * (STP1**. 5) A (1894) = A (1890) * (STP2**. 5) STPNOM= (1. +A (18 94) ) * (1. + A (1972)) IF NTIME=74 THEN STPNOM= (1.+A (1 894) ) * (1. 77/1. 56) IF NTIME=75 THEN STPNOM= (1. + A (1894) ) * (1. 95/1. 77) IF NTIME=76 THEN STPNOM= (1.+A (1894) ) * (2. 11/1. 95) EITHER USE THE ENDOGENOUS OR EXOGENOUS DEMAND SERIES IF A(2131)=0 THEN GO TO 10 QGAS-365.*DEMAND- (1.-A (2136))*LOSSGAS EQUATIONS FOR NCN-FRONTIER GAS PRODUCTION 10 GASPRO=EXG ASNF+ (QGAS+(1.-A (2 1 36) ) *LOSSGAS) /3 65. - (1.-EGASXD) *. 889*EGASD IF GASMAX=0. THEN GASMAX=GASMAX73 IF GASPROGASMAX THEN GASPRO=GASHAX IF . 365*GASPR0>J1L*RESBASE THEN GASPRC=(J1L*RESBASE)/.365 THE RESERVE EASE IS DEFINED RESBASE=J1L*RE3BASE+RESDISCV-.36 5*GASPEO GASACUM IS THE CUMULATIVE PRODUCTION IN THE SIMULATION GASACUM=J1L*GASACUM+.365*GASPRO GASPLANT IS THE NATURAL GAS PROCESSING PLANT EXPENDITURE GASPLANT=A(2141) * (. 3 65* (GASPRO-J1L*GASERC) -J1L*EXCAPGAS) IF GASPLANT<0. THEN EXCAPGAS=-.365*(GASP30-J11*GASPRO)+J1L*EXCAPGAS IF GASPLANT<0. THEN GASPLANT= 0. IF GASPLANT>0. THEN EXCAPGAS=0. RESCOST REPRESENTS THE COST OF HOLDING RESERVES RESC0ST=J1L*RESC0ST* (1. - . 36 5*GASPRO/ (J 1L*RESBASE) ) + (A (1907) * (GASACUM+RESBASE)-A(1908)+GASCADJ)*RESDISCV+GASPLANT CALCULATE THE OPERATING EXPENDITURE IF NTIME<=74 THEN A (19 09) -. 1 * (6 5. 48 81 -. 4 6 76 6 8*GAS ACUM+GASOP AD J) IF NTIME>=75 THEN A(1909)=5.4 GASCOSTM IS THE MARGINAL COST, IN 1976 CENTS/MCF, OF NEW NON-FEONTIER GAS GASC0STM=2. 11* (A (1907) * (GASACUM + RESBAS E) -A (1908) +GASCADJ) * A(1902) +A (1909) *2. 11 IF RESBASE+GASACUM>=.9999*A (19 19) THEN GASCOSTM=0. PG AS NF IS THE WELLHEAD PRICE CF NATUPAL GAS (IN CENTS PER MCF) PGASNF=100.*PGW.PR PG AS REG IS BASED CN THE TORONTO CRUDE CIL FRICE IF NTTME>=76 THEN PGASREG=100.* A(1860)*(PCW.PR+POT.PO)/A (1921) PGAS IS THE COMMODITY BASED OPPORTUNITY PRICE OF NATURAL GAS IN TORONTO TF NTIME<=73 THEN PGAS= PGAS REG IF NTIME>=74 THEN PGAS=100.*PO.OFF/A(1921) THE FOLLOWING SWITCH INDICATES THE TYPE OF PRODUCTION PROFILE IF A (1910) = . 1 THEN GO TO 31 175 ESTABLISH PRODUCTION FROM ALREADY HOCKED-UP RESERVES GASLAG=J14L*GASADD DI=A (1910) DF=DI*.15272* (. 85) ** 1 3 S2=0. DO 40 1=1,14 J1=L0(I) 40 S2=S2 + JIL*GAS ADB*DI S2=S2+GASADD*DI S3=0. DO 50 1=1,13 J1=LC(I) 50 S3=S3 + JIL*GASLAG*DI*(.85**1) S4=0. J1=L0(14) S4=S4 + JIL*GASLAG*DF GO TO 61 PRODUCTION PATTERN USING MCDANIEL EXTRACTION RATE 31 GASLAG=J3L*GASADD DI=A (1910) DF=.95*DI S2=0. DO 41 1=1,2 J1 = LC (I) 41 S2=S2 + JIL*GASADD*DI S2=S2 + GAS ADD*DI + J3L*GASADD*DF S3=0. DO 51 1=1,13 J1=LC(I) 51 S3=S3 + JIL*GASLAG*DF*(.90**1) S4 = 0. 61 GASMAX=GASMAX73 + (S2+S3+S4)/.365 DFLOW=GASMAX-GAS ACD*DI/.365 + EGASD* (1.-EGASXD)*.889 DETERMINE THE STOCK OF NEW RESERVES THAT MUST BE HOOKED-UP THIS YEAR GASADD= ( (QGAS+ (1.-A (2136))*LOSSGAS)/365.+EXGASNF-DFLOW)*.365/DI IF A(1918)<=0.0 AND GASAED>J1L*RESEXCES THEN GASADD=J1L*RESEXCSS IF A(1948)>0.0 AND NTIME>A (194 8) THEN GASADD=0.0 REMD IS THE REMAINING STOCK OF UNDISCOVERED RESERVES IF K7=1 THEN REMD=A (1919)-J1L*RESBASE-J1L*GASACUM IF (J1L*GASADT+RESDISCV)>=REMD THEN RESDTSCV=REMD-J1L*GASADT IF A(1918)>0.0 AND (J1L*GASADT+G AS ADD) >=REMD THEN GASADD= REMD-J1L*GASA IF RFSDISCV<0.0 THEN RESDISCV=0.0 IF GASADD<.01 THEN GASADD=0. G A SA DT REPRESENTS THE CUMULATIVE RESERVE DISCOVERIES GASADT=J1L*GASADT +RESDISCV DISCOVERIES FROM 1975 ARE NEB ESTIMATES FROM 1975 REPORT IF («J1L*GASADT+RESDISCV) >=REMD THEN GC TO 21 DISCOVERIES 1955-1974 ARE ACTUAL SERIES (USE PROBABLE FROM 1963) IF NTIME=55 THEN RESDISCV=2.1554 IF NTIME=56 THEN RESDISCV=2.8072 IF NTIME=57 THEN RESDISCV=1.2144 IF NTIME=58 THEN RESDISCV=2.5866 IF NTIME= = 59 THEN RESDI3CV= = 3, 3586 IF NTIME= = 60 THEN RESDISCV= = 4. 0409 IF NTIME= = 61 THEN RESDISCV= = 3. 2359 IF NTIME= = 62 THEN RESDISCV= 2. 5176 IF NTIME= = 63 THEN RESDISCV= — • 216 IF NTIME= = 64 THEN RESDISCV== 8. 329 IF NTIME= = 65 THEN RESD'ISCV= 1. 958 IF NTIME= = 66 THEN RESDISCV= 3. 941 IF NTIME= = 67 THEN RESDISCV= 2. 897 IF NTIME= = 68 THEN RESDISCV= 4. 628 IF NTIME= 69 THEN RESDISCV- 4. 836 IF NTIME= 70 THEN RESDISCV= 4. 600 IF NTIME= 71 THEN RESDISCV= 3. 628 IF NTIME= 72 THEN RESDISCV= . 835 IF NTIME= 73 THEN RESDISCV= 5. 108 IF NTIME= 74 THEN RESDISCV= 4. 8 IF NTIME= 75 THEN RSSDISCV= 3. 0 IF NTIME= 76 THEN RESDISCV= 3. 0 IF NTIME" 77 THEN RESDISCV= 2. 5 IF NTIME= 78 THEN RESDISCV= 2. 5 IF NT.IME= 79 THEN RESDISCV= 2. 0 IF NTIME= 80 THEN RESDISCV- 2. 0 IF NTIHE= 81 THEN RESDISCV= 1. 5 IF NTIME= 82 THEN RESDISCV= 1. 5 IF NTIME= 83 THEN RESDTSCV= 1. 0 IF NTIME= 84 THEN RESDISCV= 1. 0 IF NTIME> = 85 * THEN RESDISCV = 0. 5 1 7 6 WHEN GENERATING GASMAX73 SERIES, SET RESDISCV=0 IF A(1948)>0.0 AND NTTME>A (194 8) THEN RESDISCV=0.0 RESEXCES IS THE STOCK OF UNHOOKEB-UP EXCESS RESERVES 21 RESEXCES=J1L*RESEXCES+RESDISCV-GASADD IF RESEXCFS<0.0 THEN RESEXCES=0.0 TAXATION EQUATIONS FOR NON-FRONTIER GAS PRODUCTION EFFECTIVE FEDERAL AND PROVINCIAL CORPORATE TAX RATES IF NTIME=74 THEN ETXRTF=.30 IF NTIME=75 THEN ETXRTF=.28 IF NTIME>=76 THEN ETXRTF=.234 IF NTIME=74 THEN ETXRTP=.1116 IF NTIME=75 THEN ETXBTP=.1134 IF NTIME>=76 THEN ETXETP=.07579 PEXPORTG - SERIES FOR THE EXPORT PRICE OF GAS IF NTIME=74 THEN PEXPORTG=52. IF NTIME=75 THEN PEXPORTG=123.34 IF NTIME=76 THEN PEXPORTG=166.67 IF NTIME = 77 THEN PEXPORTG=194. 0 IF NTIME>=78 THEN PEXPORTG=J1L*PEXPORTG*1 .1 5 IF NTIME>78 AND PEXPOBTOPGAS THEN PEXPORTG=PGAS WEIGHTED GAS PRICE TC NON-FRONTIER PRODUCERS - EXPORT VS. DOMESTIC IF NTIME>=74 THEN PGASW= (PEXPORTG-.66*A (1901) *PEXOG/1.9 5)*EXG AS NF /GASPRO + PGASNF* (GASPRO-EXGASNF) /GASPRO YGASNFT - TAXABLE INCOME FOR NON-FRONTIER GAS PRODUCTION IF NTIME<=73 THEN YGASNFT-3.65*GASPRO*(PGASNF-(A(1909) + A (1906))*PGNE-A (19 04) *PG AS NF) - (. 36 5*GASPRO /J1L*RESBASE)*RESCOST*PEXOG IF NTIME=74 THEN YGASNFT=3.65*GAS PRO* (PGASNF- (A (1909) + A (1906) ) *PGNE) - (. 365*GASPR0/J1L*RESBASE) *RESCOST *PEXOG IF NTIME>=75 THEN YGASNFT=3.65*GASPBO*(PGASW- (A (1909) + A (1906))*PGNE) - (. 365*GASPR0/J1L*RESBASE) *RESCOST *PEX0G FRACTION OF TAXABLE PROFITS ALLOWED FOB EARNED DEPLETION IF NTIME>=74 THEN DEPLE= (PEXOG*. 3 33*(A (1907)* (GASACUM+RESBASE)-A(1908) + GASCADJ)*RESDISCV+GASPLANT*PGNE+J1L*KEDFNF$) /YGASN FT IF NTIME<=73 THEN REDPA=.333 IF NTIME>=74 AND EEPLEO.25 THEN REDPA=DEPLE IF NTIME>=74 AND EEPLE>.25 THEN REDPA=.25 KEDP NF$ - STCCK OF UNCLAIMED EABNED DEPLETION IF UTIME>=70 AND NTIME<=73 THEN KEDPNF$=PEXOG*. 333* (A(1907)* (GASACUM+RESBASE) -A (1908) +GASCADJ)*RESDISCV+GASPLANT*PGNE+J1L*KEDPNF$ IF NTIME>=74 THEN KEDPNF$= (DEPLE-REDPA)*YGASNFT TCGASNF - CORPORATION TAX CN NCN-FRONTIER GAS PRODUCTION IF NTIME<=73 THEN TROYLG=0. IF TROYLG<0. THEN TROYLG=0. IF NTIME=74 THEN TR0YLG= (GASPR0-GASMAX73)* (8. 54+. 35*(PGASNF -36.)) + (GASKAX73* (9.22 + .50* (PGASNF-36.)))*3.6 5 -. 3 5* (. 04*PEXOG/1.7 7*RESDISCV) IF NTIME>=75 THEN TROYLG= (GASPRO-GASMAX73) * ( 8. 54 + . 35* (PGASW -36.))+ (GASMAX73*(9.22+.50* (PGASW-36.)))*3.65 -.45* (. 04*PEXOG/1.77*RESDISCV) IF NTIME<=73 THEN TCGASNF=A (1888)*(1.-REDPA)*YGASNFT IF NTIME>=74 THEN TCGASNF=£TXRTF* (1.-BEDPA) *YGASNFT + ETXRTP* (1. -REDPA) * (YGASNFT-TROYLG) RENT EQUATIONS FOR NCN-FRONTIEB GAS PBCDUCTION B.C. INDEMNIFICATION OF FEDEBAL TAXES PAID BY PRODUCERS RE: GAS ROYALTIES (DEEMED AND ACTUAL) IF NTIME=74 THEN BCINDM=ETXRTF*.1394*TBOYLG IF NTIME>=75 THEN BCINDM=ETXRTF*.16*TROYLG ALBEBTA SELECTIVE ROYALTY REDUCTION, A CASH TRANSFER TO PRODUCERS IF NTIME>=74 THEN REBATE=15.+.0262*TROYLG KRNFGP$ - PROVINCIAL GOVERNMENT RENT EQUATIONS IF NTIME<=73 THEN KRNFGP$=J1L*KRNFGP$*STPN0M + ( (A (1906) *PGNE +A (1904) *PGASNF) *3.65*GASPRO + A (1916)* (TCGASNF-A (189 5)*PEXOG*RESCOST) ) * (STPNOM**. 5) IF NTIME=74 THEN KBNFGP$=J1L*KRNFGP$*STPNOM+(A(1906)*PGNE *3.65*GASPRC + TR0YLG+ETXRTP* (1.-REDPA) * (YGASNFT -TROYLG) + (PEXPORTG- PG AS N F- . 66 * A (1901) *PEXOG/1 .95) *EXGASNF*3. 65* (1.-ETXBTF) -BCINDM-REEATE- (A(1895)*PEXOG*RESCOST)*A(1916) ) * (STPNOM**. 5) IF NTIME>74 THEN KBNFGP$=J1L*KRNFGP$*STPNOM+(A(1906)*PGNE *3.65*GASPRC + TROYLG + ETXRTP* (1.-REDPA) *(YGASNFT -TRCYLG) -BCINDM-REBATS- (A (1 895) *PEXOG*RESCOST)*A (19 16) ) * (STPNOM**. 5) KR NF GE $ - FEDERAL GOVERNMENT RENT EQUATIONS IF NTIME<=73 THEN KRNFGF$=J1L*KRNFGF$*STPNOM+ ((1.-A(1916) ) *(TCGASNF-A (1895)*PEXOG*RESCOST) ) * (STPNOM**. 5) IF NTIME=74 THEN KRNFGF$=J1L*KRNFGF$*STPNOM +(ETXRTE*(1.-REDPA)*YGASNFT - (A (1895) *PEXOG*RESCOST) * (1. - A (1916) ) + ETXRTF*3.6 5*(PEXPORTG-PGASNF-.66*A (1901) *PEXCG/1.95) *EXGASNF) * (STPNOM**. 5) IF NTIME>74 THEN KRNFGF$=J1L*KRNFGF$*STPNCM + (ETXRTF*(1.-REDPA) *YGASNFT - (A (1895) *PEXOG*RESCOST) * (1 . - A (19 16) ) ) * (STPNCM** . 5) KRENTNF$ - PRODUCER RENT EQUATIONS IF NTIME<=73 THEN KRENTNF$=J1L*KRENTNF$*STPNOM+(3.65*GASPRO * (PGASNE- (A (1909) +A (1906) ) *PGNS-A (1904) *PGASNF) -TCGASNF - (A (1890) +.365*GASPR0/J1L*RESEASE) *PEXOG*RESCOST ) * (STPNOM**. 5) IF NTIME=74 THEN KRENTNF$=J1L*KRENTNF$*STPNOM+(3.65*GASPRO * (PGASNF- (A (1909) + A (1906) ) *PGNE) -TROYLG-TCG ASNF+ BCIN DM + R EBATE - (A (1890) +. 365*GASPRO/J1L*RESBASE) *PEXOG*RESCOST )*(STPNOM**.5) IF NTIME>=75 THEN KRENTNF$=J1L*KRENTNF$*STPNOM+(3.65*GASPRO * (PGASW- (A (190 9) + A (1906) ) *PGNE) -TROYLG-TCGASNF+ BCINDM+REBATE -(A(1890) +. 365*GASPR0/J1L*RESBASE)*PEXOG*RESCOST ) * (STPNCM**. 5) KRENTC1 $ RENTS TO CANADIAN USERS OF NON-FRONTIER GAS KRENTC1$- (3.65* (PGAS-PGASREG) * (GASPRO-EXGASNF) ) * (STPNOM**.5) +J1L*KRENTC1$* (STPNCM) IF KRENTC1$<1. THEN KRENTC1$=0. KRENTC2$ - RENTS TO AMERICAN USERS OF CANADIAN NCN-FRONTIER GAS KRENTC2$=J1L*KRENTC2$*STPNOM+ (3.65*EXGASNF *(PGAS-FEXPORTG-A (2139)) ) * (STPNOM**. 5) KRENTGAS - TOTAL RENTS FROM NCN-FRONTIER GAS PRODUCTION IF NTIME<=73 THEN A (2138)=PEXPORTG-PGASNF IF NTIME>=74 THEN A (21 38) =. 66*A (1 901) *PEXOG/1. 95 IF NTIME<=73 THEN A{2139)=11. IF NTIME>=74 THEN A (2139)=11.*PSXOG/1.56 KRENTGAS=J1L*KRENTGAS*STPNOM+(3.65*GASFRO * PG AS- (A (1890) + A (1895) +. 365*G ASPRO/J1 L*RESBAS E) *PEXOG*RESCOST-3.65* (GASPRO-EXGASNF)*1. 16 *A (1901) *PEXOG/1. 95-3. 65*EXGASNF* (A (2 138) +A (2 139) ) -3.65*GASPRO*A (1909)*PGNE ) * (STPNOM**. 5) CALCULATE THE PRESENT VALUE OF THE RENTS IN THE LAST SIMULATION Y IF K7=M9 THEN IF K7=M9 THEN IF K7=M9 THEN IF K7=M9 THEN IF K7=M9 THEN IF K7=M9 THEN KfiENTNF$=KRENTNF$/ (STPNOM** (K7-3)) KRNFGP$=KRNFGP$/ (STPNOM** (K7-3) ) KRNFGF$=KRNFGF$/(STPNOM** (K7-3) ) KRENTC1$=KRENTC1$/( (STPNOM) ** (K7-3) ) KBENTC2$=KRENTC2$ / (STPNCM** (K7-3) ) KRENTGAS=KRENTGAS /(STPNOM** (K7-3)) RENTCA NT - TOTAL RENTS ACCRUING TO CANADIANS FRCM NON-FRONTIER FRONTIER GAS, AND THE MACKENZIE VALLEY PIFELINE RENTCANT=RENTCAN$+KRENTGAS-.785*KRENTNF$-KRENTC2$ EXPORTS EXPORTS=EXGASNF*.365 XBALGO$ IS THE TRADE ACCOUNT BALANCE ON OIL AND GAS XBALGO$=10.*EXPORTS*PEXPOETG+.365*CILXTOT*POILUS -.365*FO.OFF*OILIMPT CANADIAN REQUIREMENTS FOR NATURAL GAS CAN. REQ. = (QGAS+ (1.-A (2136) ) *LOSSGAS) /1000. THE DESIRED FLOW OF PRODUCTION FROM CANADIAN SOURCES SUM=EXPORTS+CAN.REQ. THE DEFICIT IN NATURAL GAS PRODUCTION DEFICIT=SUM/. 365-GASMAX- (1.-EGAS XD)*. 889*EGASD IF DEFICIT<=0. THEN DEFICIT=0. GASMAXA IS THE ANNUAL FLOW OF GASMAX GASMAXA=GASMAX*.365 IF GASMAXA<.01 THEN GASMAXA=0. NCN FRONTIER GAS PRODUCTION 2. EQUATIONS FOR EXOGENOUS VARIABLES SET THE ROYALTY RATE COEFFICIENT IF NTIME<74 THEN A (1904) = . 16666667 IF NTIME>=74 THEN A (1904)=.25 SET THE COST COEFFICIENTS FOR EXPLORATION AND DEVELOPMENT IF NTIME<67 THEN A (1907)=. 162781 IF NTIME<67 THEN A ( 1 908)=-3. 32951 IF NTIME>=67 THEN A (1907) = , 637365 IF NTIME>=67 THEN A (1908) =1 6. 6332 SET THE COEFFICIENT FOR GAS PLANT EXPENDITURE IF NTIME> = 58 THEN A (214 1) = 443.094+GASPLADJ IF NTIME>=74 THEN A (21 4 1) = 4 4 3 . 0 94 SET THE COEFFICIENT FOR EXPENDITURE ON LANE ACQUISITION IF NTIME>=58 THEN A (1906)=2. 51086 + GASLADJ IF NTIME>=75 THEN A (1906)=2. 51086 PGASREG IS THE REGULATED TORONTO CITY GATE PRICE IF N TIM E= = 55 THEN PGASR EG= = 39.4 IF NTIME= = 56 THEN PGASREG= = 39.6 IF NTIME= = 57 THEN PGASREG= 40.0 IF NTIME= = 58 THEN PG ASR EG= = 38.5 IF NTIME= 59 THEN PGASREG= = 38. 6 IF NTIME= = 60 THEN PGASREG= = 39.0 IF NTIME= = 61 THEN PGASREG= 41. 9 IF NTIME= 62 THEN PGASREG= = 42.6 IF N.TIME= 63 THEN PG ASREG= 43.8 IF NTIME= 64 THEN PGASREG= 44. 4 IF NTIME= 65 THEN PGASR EG= 44. 4 IF NTIME= 66 THEN PGASREG= 45. 1 IF NTIME= 67 THEN PG ASREG= 45.6 IF NTIME= 68 THEN PGASREG= 45.7 IF NTIME= 69 THEN PGASRFG= 45. 7 IF NTIME= 70 THEN PGASREG= 46.4 IF NTIME= 71 THEN PGASREG= 46. 2 IF NTIME= 72 THEN PGASSEG= 46.9 IF NTIME= 73 THEN PGASREG= 53. 3 IF NTIME= 74 THEN PGASREG= 82. IF NTIME= 75 THEN PG ASREG= 100. PEXOG IS THE ASSUMED RATE OF INFLATION IF NTIME<=73 THEN IF NTIME>=74 THEN IF NTIME<=72 THEN IF NTIME=73 THEN IF NTIME=74 THEN IF NTIME=75 THEN IF NTIME=76 THEN IF NTIME>76 THEN A (1972) = . 037752 A (1972) =.04 PEXOG= (1. +A (197 2) ) ** (NTIME-61) PEXOG=1.56 PEXOG=1.77 PEXOG=1.95 PEXOG=2.11 PEXOG=J1L*PEX0G* (1. + A(1 972)) SET THE NATURAL GAS TRANSPORTATION TARIFF IF NTIME<=72 THEN A(1901)=30.*1.95/1.16/PEXOG IF NTIME=73 THEN A(1901) = 35.* 1.95/1 . 16/PEXOG IF NTIME>=74 THEN A(1901)=42. IF APPLICABLE, DEMAND IS THE EXOGENOUS DEMAND SERIES IF NTIME=73 THEN DEMANE=3.937 IF NTIME=74 THEN DEMAND=4.216 IF NTIME=75 THEN DEMAND=4.347 IF NTIME>=76 THEN DEMAND=1. 08*J 1L*DEMAND IF NTIME>=77 THEN DEMAND=5.070*((1.05)**(NTIME-77)) * ( (49.10*J3L*PEXOG/J3L*PGASREG) **.2) DE MA NDA INTRODUCES SPECIFIC DEMAND FORECASTS IF NTIME>=91 THEN DEMANDA=J1L*DEMANDA+1.047 IF DEMANDA>0.0 THEN DEMAND=DEMANDA/365. EXGAS11F IS THE APPROVED EXPORT SERIES FOR NATURAL GAS IF NTIME= = 55 THEN EXGASNF= = 1 1. 16/365. IF NTIME= = 56 THEN EXGASN F-= 10. 64/365. IF NTIME-= 57 THEN EXGASNF= = 21. 34/365. IF NTI ME= = 58 THEN EXGASNF= =90.26/365. IF NTIME-= 59 THEN EXGASNF= =83.71/365. IF NTIME= = 60 THEN E X G A S N F= = 1 10. 37/365. IF NTIME-= 61 THEN EXGASNF= =164.34/365. IF NTIME= = 62 THEN EXG ASN F= = 339. 18/365. IF NTIHE= = 63 THEN EXGASNF= =355.57/365. IF NTIHE= = 64 THEN EXGASNF= = 386. 38/365. IF NTIME= = 65 THEN EXGASN F = =390.92/365. IF NTIME-= 66 THEN EXGASNF-= 391. 18/365. IF NTIME= = 67 THEN EXGASNF= = 463. 03/365. IF NTIME= = 68 THEN EXGASNF= = 519. 75/365. IF NTIME= = 69 THEN EXGA SN F = = 645. 82/365. IF NTIME= = 70 THEN EXGAS NF= = 772. 44/365. IF NTIME= = 71 THEN EXGASNF= = 898. 27/365. IF NTIME= = 72 THEN EXGASN F= 999. 16/365. IF NTIME= = 73 THEN EXGASNF= 1017.9/365. IF NTIME= = 74 THEN EXGASN F= 2. 80 IF NTIME= =75 THEN EXGASNF= 2. 77 IF NTIME= = 76 THEN EXGASNF- 2. 76 IF NTIME= 77 THEN EXGASNF= 2.77 IF NTIME= =78 THEN EXGASNF= 2. 78 IF NTIME= 79 THEN EXGASNF= 2. 74 IF NTIME= = 80 THEN EXGASNF= 2. 73 IF NTIME= 81 THEN EXGASNF= 2. 72 IF NTIME= 82 THEN EXGASNF= 2. 37 IF NTIME= 83 THEN EXGASNF= 2. 34 IF NTIME= 84 THEN EXGASN F= 2, 32 IF NTIME= 85 THEN EXGASN F= 2. 29 IF NTIME= 86 THEN EXGASNF= 2. 09 IF NTIME= 87 THEN EXGASNF= 1. 72 IF NTIME= 88 THEN EXG AS N F= 1.71 IF NTIME= 89 THEN E X G A S N F= 1.54 IF NTIME= 90 THEN EXGASNF= . 57 IF NTIME= 91 THEN EXGASNF= . 32 IF NTIME= 92 THEN EXGASNF— . 15 IF NTIME= 93 THEN EXGASNF- . 1 3 IF NTIME= 94 THEN EXGASNF= .02 IF NTIME= 95 THEN EXGAS NF= . 02 IF NTIME> = 96 THEN EXGASNF = 0. GMAX A IS USED TO READ IN AN OPTIONAL GASMAX73 SERIES IF GMAXA>0.0 THEN GASMAX73=GMAX A/365. 2.C NCN FRONTIER CONVENTIONAL CRUEE OIL PRODUCTION 182 1. EQUATIONS FOR ENDOGENOUS VARIABLES THE SWITCH ALLOWS EITHER AN ENDOGENOUS OR EXOGENOUS DEMAND SERIES IF A(2131)=0 THEN GO TO 10 IF NTIME=73 THEN QOILEAST-319.121-LGILEAST IF NTIME=74 THEN QOTLEAST=326.131-LOILEASI IF NTIME=73 THEN QOILWEST=297.006-LOILWEST IF NTIME=74 THEN QOILWEST=3 19.626-LOIIWEST NEB DEMAND GROWTH ASSUMPTIONS - TO BE USED IF DEMAND IS EXOGENOUS IF NTIME>=75 THEN QOILEAST=1.031*J1I*QOTIEAST IF NTIME>=75 THEN QOILWEST=1.031*J1L*QOILWEST OIL PRODUCTION 10 OILPRO=(QOILWEST+LOILWEST)/. 365 +A (194 1) +OILEXPT-GCOSPRO-CPROSUM DESPRO IS THE DESIRED PRODUCTION DESPRO=OILPRO IF OILPROOILMAX THEN OILPRO=OTLMAX IF .365*CILPR0>J1L*0ILREASE THEN OILPBO=J1L*0ILRBASE/.365 OIL RESERVE EASE 0I1RBASE=J1L*0ILRBASE+0ILRDISC-.365*01LPRO ACCUMULATION CF OIL PRODUCTION 0ILACUM=J1L*CILACUM+.365*OILPRO COST OF HOLDING RESERVES 0ILPC0ST=J1L*0ILRC0ST*(1.-.36 5*OILPRO/J1L*CILRBASE) + (A (1933)* (OILACUM + OILREASE) -A (1934) +OILCADJ)*OILRDISC SET THE OPERATING COST COEFFICIENT IF NTIME<=74 THEN A (1936) = . 449909-. 0000 33 0268*OILACUM+OILOPADJ IF NTIME>=75 THEN A (1936) =. 20 SET THE COEFFICIENT FOR LAND ACQUISITION EXPENDITURE IF NTIME>=58 THEN A (1944) = . 690395-. 000091 11 48*OILACUM+OILLADJ IF NTIME>=75 THEN A (1944)=.08214 MARGINAL COST OF FINDING, DEVELOPING AND PRODUCING OIL RESERVES OILCOSTM=2.11*(A (1933)*(OILACUM+OILRBA SE)-A(1934)+OILCADJ) *A (1935)+A (1936) *2. 11 IF (OILACUM+OILRBASE)>=A (1937) THEN OILCOSTM=0.0 US MID-WEST PRICE OF OIL; AND EXPORT TAX RATE, $/BBL POILUS=PO.OFF+A(1938)*PEXOG/1.56 IF NTIME>=74 THEN RTOILEXP=POILUS-POW.PR-A(1940)*PEXOG/1. 56 TXOIL IS THE FEDERAL GOVSEMENT REVENUE FROM THE EXPORT TAX TXOIL=.365*OILXTOT*RTOILEXP CALCULATE MAXIMUM FLOW FROM EXISTING STOCK OF RESERVES OILLAG=J8I*GILADD DI = A (1942) DF=DI*. 308 92915* (. 85)**15 DH=.5*DI IF <OILPRO-J1L*OILPRO)/J1L*0ILPRO>A(1949) AND NTIME<=56 THEN DH= (. 5 + A (1951) ) *DI IF (OILPBO-J1L*OILPEO)/J1L*CILPBO>A(1950) AND NTIME>=57 THEN DH= (. 5 + A (1951) ) *DI S2=DH*OILADD DO 4 0 1=1,8 J1 = L0(I) 40 S2=S2+JIL*OILADD*DI S3=0.0 DO 50 1=1,15 J1 = L0(I) 50 S3=S3+JIL*0IL1A6*BI*(.85**1) S4=0.0 J1 = LC(16) S4=S4+JIL*CILLAG*DF OILMAX=OILMAX74+(S2+S3 + S4)/. 365 IF EXCESS CAPACITY EXISTS THEN REDUCE FLOW FROM PREVIOUS OILADD1S IF OILMAX-OILADD*DH/.365>DESPRO THEN EXCESS= (OILMAX-DESPRO)/((S2+S3+S4) /.365) IF OILMAX-OILADD*DH/.365>DESPRO THEN CILADD=0.0 OILPIPEM IS THE THROUGHPUT OF THE MONTREAL PIPELINE OILPIPEM=A(1941) IF DESPRO>OILMAX THEN OILPIPEM=OILMAX-DESPRO+ A(1941) MAXIMUM PRODUCTION FLOW NET OF ANY CURRENT ADDITIONS OILFLO=OILMAX-OILA DD*DH/.365 CALCULATE AMOUNT OF RESERVES TO BE HOOKED UP TO MEET CURRENT DEMAND IF DESFRC>=OILFLC THEN OILADD=(DESPRO-OILFL0)*.365/DH IF A(1948)>0.0 AND NTIME>A(1948) THEN OILADD=0.0 REMD REPRESENTS THE ULTIMATE STOCK OF UNDISCOVERED RESERVES IF K7=1 THEN REMD=A ( 1937)-J1L*OILRBASE-J1L*CILACUM TOTAL DISCOVERIES OF EESERVES FROM BEGINNING OF SIMULATION' OILDISCT=J1L*CILDISCT+OILRDISC IF OILDISCT>=REMD THEN GO TO 21 WHEN GENERATING OILMAX74 SET OILRDISC=0 IF NTIME>=47 AND NTIME<=50 THEN OILRDISC=0.0 DISCOVERIES FROM 1947-1974 ARE ACTUAL SEBIES DISCOVERIES FROM 1975 ARE THE GULF SERIES IF NTIME= = 51 THEN OILRDISC= = 221.311 IF NTIME= = 52 THEN OILRDISC= =363.409 IF NTIME= = 53 THEN OILRDISC= •246.823 IF NTIME= = 54 THEN OILRDISC= = 457.808 IF NTIME= 55 THEN OILRDISC= 429.427 IF NTIME= 56 THEN OILRDISC= 509.157 IF NTIME= 57 THEN OILRDISC= 206.837 IF NTIME= 58 THEM OILRDISC= 457.495 IF NTTME= 59 THEN OILRDISC= 514.959 IF NTIME= 60 THEN OILRDISC= 372.522 IF NTIME= 61 THEN OILRDISC= 716.055 IF NTIME= 62 THEN OILRDISC= 522.016 IF NTIME= 63 THEN OILRDISC= 657.277 IF NTIME= 64 THEN OILRDISC= 1566.953 IF NTIME= 65 THEN OILRDISC=-825.183 IF NTIME= 66 THEN OILP.DISC= 1396.567 IF NTIME= 67 THEN OILRDISC= 721.329 I F NTIME=68 THEN IF NTIHE=69 THEN IF NTIME=70 THEN IF NTIME=71 THEN IF NTIMS=72 THEN IF NTIME=73 THEN IF NTIME=74 THEN IF NTIME=75 THEN IF NTIME=76 THEN IF NTIHE=77 THEN IF NTIME=78 THEN IF NTIME=79 THEN IF NTIME=80 THEN IF NTTME=81 THEN IF NTIME=82 THEN IF NTIME=83 THEN IF NTIME=84 THEN IF NTIME=85 THEN IF NTIME=86 THEN IF NTIME=87 THEN IF NTIME=88 THEN IF NTIME=89 THEN IF NTIME=90 THEN IF NTIME=91 THEN IF NTIME=92 THEN IF NTIME=93 THEN IF NTIME>=94 THEN OILRDISC=584. 1 57 OILRDISC=631.595 OILRDISC=377. 1 98 OILRDISC=254.233 OILRDISC=205. 074 OILRDISC=279.668 OILRDISC=98. 234 0I.LRDISC=181 .0 OILRDISC=168.0 OTLRDISC=156.0 OILRDISC=147.0 OILRDISC=135.0 OILRDISC=129.0 OILRDISC=118.0 0ILSDISC=112.0 OILRDISC=103.0 OILRDISC=9 5.0 OILRDISC=91.0 0ILRDISO82. 0 OILRDISC=76.0 OILRDISC=73.0 OILRDISC=69.0 0ILEDISO65. 0 OTLRDISC=61.0 OILP.DISC=56. 0 OILRDISC=52.0 184 0ILRDISO50.0 IF A(1948)>0.0 AND NTIHE>A (1948) THEN IF (J1L*CILDISCT+0ILRDISC)>=REMD THEN IF OILRDISC<0.0 THEN OILRDISC=0.0 IF OILADD>(J1L*OILREXES + OILRDISC) THEN IF CILADD<0.0 THEN OILADE=0.0 OILRDISC=0.0 0TLRDISC=REMD-J1L*0ILDISCT 0ILADD=JTL*0ILREXES+OILBDISC EXCESS OIL RESERVES OILREXES=J1L*CILREXES+OILRDISC-OILADD ADD TO OILREXES IF OILMAX74>CILPRO IF OILHAX74>DESPRO THEN OILREXES=J1L*CILREXES+.365*(OILMAX74-DESPRO) +CILRDTSC IF OILMAX74>DESPRO THEN EXCESS=0.0 IF OILREXES<0.0 THEN OILREXES=0.0 TAXATION EQUATIONS FOR NON-FRONTIER OIL PRODUCTION EFFECTIVE FEDERAL AND PROVINCIAL CORPORATE TAX RATES IF NTIME=74 THEN ETXRTF=.30 IF NTIME=75 THEN ETXRTF=.28 IF NTIME>=76 THEN ETXRTF=.234 IF NTIME=74 THEN ETXRTP=.1116 IF NTIME=75 THEN ETXRTP=.1118 IF NTIHE>=76 THEN ETXRTP=.07306 TAXABLE INCOME OF NCN-FRONTIER OIL PRODUCTION IF NTIME<=73 THEN YOILNFT = . 365*OILPRO* (POW.PR-A (1 936) *PGNE-A (1944) * PG NE-A (1945)*POW.PR)-(. 365*01LPRO/J1L*CILRBASE) *OILRCOST*PEXOG IF NTIME>=74 THEN YOILNFT=. 36 5*OILPPO*(POW.PR-A(1936) *PGNE-A(19 44)* PGNE)- (. 365*0ILPR0/J1L*0ILREASE)*OILRCOST*PEXCG FRACTION OF TAXABLE PROFITS ALLOWED FOR EARNED DEPLETION IF NTIME>=74 THEN DEPLE= (PSXOG*.333* (A (1933)* (OILACUM+OILRBASE)-A(1934) +OILCADJ) *0ILRDISC+J1L*K0.ILEDP$) /YOILNFT IF NTIME<=73 THEN OILREDPA=.333 IF NTIME>=74 AND DEPLEO.25 THEN GILREDPA=DEPLE IF NTIME>=74 AND EEPLE>.25 THEN OILREEPA=.25 STOCK OF UNCLAIMED EARNED DEPLETION IF NTIME>=70 AND NTIME<=73 THEN KOILEDF$= (PEXOG*.33 3*(A(1933)*(OILACUM+OILRBASE) -A (1934) + OILCADJ) *CILRCISC + J1L*KCILEEP$) IF NTIME>=74 THEN KOILEDP$= (DEPLE-OILREDPA)*YOILNFT COPPORATICN TAX CN NCN-FRONTIER CIL PRODUCTION IF NTIME<=73 THEN TROYLO=0. IF TROYLO<0. THEN TROYLO^O. IF NTIME=74 THEN TROYLO=.365*CILPROLD*(.40*POW.PR) + .365* (OILPRO-OILPROLD) * (. 2 8*POW. PR) - .35* (. 40*OILRDISC) IF NTIME>=75 THEN TROYLO=.365*OILPROLD*(.36*PCW.PR) + .365* (OILPRO-CILPROLB) * (. 27*POW. PR) -.45* (. 40*CILRDISC*PEXOG/1. 77) IF NTIME<=73 THEN TCOILNF=A (1946)*(1.-OILREDPA) *YOILNFT IF NTIME>=74 THEN TCOILNF=ETXRTF* (1.-OILREDPA)*YOILNFT+ETXRTP*(1.-0ILREDPA) * (YCILNFT-TROYLO) EXPORTS OILXTOT=OILEXPT CANADIAN DEMAND FOR CRUDE OIL OILCAND= (QOILEAST+LOILEAST+QOILWEST + LOILWEST)/.365 OIL IMPORTS OILIMPT=OILCAND+OILXTOT-OILPRO-CPROSUM-GCOSPRO XBALGOS IS THE TRADE ACCOUNT BALANCE ON OIL AND GAS XBALGO$=10.*EXPORTS*PEXPORTG+.365*OILXTOT*POILUS -.365*PO.OFF*OILIMPT DESIRED PRODUCTION FRCM NON-FRONTIER SOURCES OILSUM=DESPRO OIL DEFICIT FRCM NON-FRONTIER SOURCES OILDEF=OILSUM-OILPRO ECONOMIC RENT EQUATIONS FOR NCN-FRONTIER OIL PRODUCTION SET THE NOMINAL DISCCUNT RATE STP1 = 1. +A (1890) * ( (1. + A (1890) ) **. 5) STP2=1.+A (1890) * (STP1**. 5) A (1894) = A (1890) * (STP 2**. 5) STPNOM= (1.+A(1894))*(1.+A (1972)) IF NTIME=74 THEN STPNOH= (1. + A (1 894) ) * (1 . 77/1. 56) IF NTIME=75 THEN STPNOM= (1. +A (1 894) ) * (1, 95/1. 77) IF NTIME=76 THEN ST PNO M= (1.+A (189 4) ) * (2. 11/1. 95) B.C. INDEMNIFICATION OF FEDERAL TAXES PAID BY PRODUCERS RE: Oil- ROYALTIES IF NTIME>=74 THEN BC.IN DM = ETXRTF*. 032* TROYLO 186 ALBERT A SELECTIVE ROYALTY REDUCTION, A CASH TRANSFER TO PRODUCERS IF NTIME>=74 THEN REBATE=15.+.0263*TROYLO PROVINCIAL GOVERNMENT RENT EQUATIONS IF NTIME<=73 THEN KRCILGP$= J1L*KR0ILGP$*STEN0M+{ (M1944) *PGNE+A (1945) *P0W. PR) *. 365*OILPRO+A (1952)*(TCOILNF-A(1895)*PEXOG*OILRCCST) ) * (STPNOM**. 5) IF NTIME>=74 THEN KROILGP$=J1L*KR0ILGP$*STPHOB+ (A (1944) *PGNE*.365*0ILPRO +TROYLO+ETXRTP*(1.-OILREDPA)*(YOILNFT-TROYLC)-BCINDM-REBATE - (A (1895) *PEXOG*OILRCOST) *A (1 95 2) ) * (STPNOM**. 5) FEDERAL GOVERNMENT RENT EQUATIONS IF NTIME<=73 THEN KROILGF$=J1L*KROILGF$*STFNOM+ (1.-A (1952)) *(TCOILNF -A(1895)*PEXOG*0ILRCOST) *(STPNOM**.5) IF NTIME>=74 THEN KROILGF$=J1L*KEGILGF$*STPNOM+ (ETXRTF* (1.-OILREDPA)*YOILNFT - (A (1895) *PEXOG*OILRCOST) * (1. - A (1 952) ) + TXOIL-GFSUBO) * (STPNOM**. 5) PRODUCER RENT EQUATICNS IF NTIME<=73 THEN KROILP$=J1L*KROILP$*STPNCM+(. 36 5*OILPEO* (POW.PR -A (1936) *PGNE -A (194 4) *PGNE-A (1945) * POW. PR) -TCOILNF- (A (1890) +. 365*OILPRO/J1L*OILRBASE) *PEXOG*OILRCCST)* (STPNOM**.5) IF NTIME>=74 THEN KROILP$=J1L*KROILP$*STPNOM+ (. 365*CILPEO* ( EOW.PR -A (1936) *PGNE-A (1944) *PGNE) -TCOILNF-TROYLO+BCINDM+REBATE - (A (1890) +. 365*CILPRO/J1L*OILRBASE) *PEXOG*OILRCOST) * (STPNOM**. 5) RENTS TO CANADIAN OIL CONSUMERS KROILC1$=J1L*KROILC1$*STPNOM + (STPNOM**.5) * ( (OILPRO-OILXTOT) *. 365* (PO. GFF-POW. PR-POT.PO) +GFSUBC) TOTAL RENTS FOR NON-FRONTIER OIL PRODUCTION IF NTIME<=73 THEN KRENTCIL=J1L*KRENTOIL*STPNOM+ (STPNOM**. 5) * (. 365*CILPRO* (PO.OFF-A (1936) *PGNE) - (A (1890) +A (18 95) +. 365*OILPRO/J 1L*OILRBASE) *PEXOG*CILRCOST - (. 365*OILXTOT*(PO.OFF-POH.PR)) - (. 365*(CILPRO-CILXTOT) *FOT.PO) ) IF NTIME>=74 THEN KRENTGI1=J1L*KRENTOIL*STPNOM+ (STPNOM**. 5) * (. 365*CILFRO* (PO.OFF-A (1936) *PGNE) - (A (1890) +A (1895) +. 365*CILPRO/J 1 L*OILRBASE) *PEXOG*OILRCOST - (. 365* (CILPRO-CILXTOT) *FOT.PC) ) CALCULATE THE PRESENT VALUE CF THE RENTS IN THE LAST SIMULATION YEAR IF K7=M9 THEN KROILGP$=KROILGP$/(STPNOM**(K7-3)) IF K7=M9 THEN KRCILGF$ = KROILGF$/(STPNOM** (K7-3)) IF K7=M9 THEN KBOILP$=KBOILP$/(STPNOH**(K7-3) ) IF K7=M9 THEN KRCILC1$ = KROIIC1$/(STPNOM**(K7-3) ) IF K7=M9 THEM KRENTOIL= KRENTOIL/ (STPNOM** (K7-3) ) TOTAL CANADIAN RENTS FRCM NCN-FRONTIER OIL PRODUCTION KROIXCAN=KRCILGP$ + KRCILGF$ + .215*KROILP$ +KROILC1 $ NC N FRONTIER OIL PRODUCTION 2. EQUATIONS FOR EXOGENOUS VARIABLES 188 SET OILPROLD EQUAL TO FRACTION OF OILMAX74 (USED FOR ROYALTY EQUATION) IF NTIME>=74 THEN 0ILP RCLD=OILM AX74 *, 99** (NTI ME-74) SET THE COEFFICIENTS FOR THE EXPLORATION AND DEVELOPMENT COSTS IF NTIME<67 THEN A (1933)= -. 0000676273 IF NTIME<67 THEN A (1934)=-. 9123 65 IF NTIME>=67 THEN A (1933) = . 000393415 IF NTIME>=67 THEN A (193 4)=4. 41140 SET THE COEFFICIENT FOE THE ROYALTY RATE IF NTIME<74 THEN A (1945)=. 140 IF NTIME<62 THEN A (1945) = . 125 IF NTIME>=74 THEN A (1945) =. 40 SET GCOSPRO=50 UNTIL 1977, AND THEN =65. AFTER 1977 IF NTIME>=75 THEN GCOSPRO=50.0 IF NTIME>=78 THEN GCOSPRO=65.0 SET MONTREAL PIPELINE FLOW IF NTIME= = 58 THEN A (1941) = -11. 128 IF NTTME= 59 THEN A (1941) -6.534 IF NTIME= 60 THEN A (1941) -10.00 3 IF NTIME= 61 THEN A(1941) -6.505 IF NTIME> =62 AND NTIME<=72 THEN IF NTIME= 73 THEN A (1941) 15. 2 IF NTIME= 74 THEN A (1941) = 64. 8 IF NTIME= 75 THEN A(1941) 6. 2 IF NTIME= 76 THEN A (1941) -100. 0 IF NTIME= 77 THEN A (1941) = 250. 0 IF J1L*EXCESS<=0.0 THEN GO TC 12 INCREASE PRODUCIBILITY FOR ONE YEAR DUE TO CUTBACK LAST YEAR DO 10 1=1,8 J1=LO(I) 10 JII*OILADD=JIL*OILADB* (1.+J1L*SXCESS) DO 11 1=1,16 J1 = L0(I) 11 JIL*OILIAG=JIL*OILLAG*(1.+J1L*EXCESS) 12 IF J2L*EXCESS<=0.0 THEN GO TO 16 RESTORE PRODUCTION RATE AS IT WAS BEFORE INCREASED LAST YEAR DO 13 1=1,8 J1 = LC(I) 13 JIL*OILADD=JIL*OILADD/(1.+J2L*EXCESS) DO 15 1=1,16 J1=LC (I) 15 JIL*CILLAG=JIL*OILLAG/(1.+J2L*EXCESS) 16 CONTINUE IF K7=1 THEN GO TO 17 DI = A (1942) IF (J1L*CILPRO-J2L*OILPR0)/J2L*0ILPR0>A(1949) AND NTIME<=57 THEN J1L*CILADD= ( (1.- (. 5 +A (1951) ) *DI) / (1 .-. 5*DI) ) *J1L*0ILACD IF (J1L*CILPR0-J2L*0TLPR0)/J2L*OILPRO>A(1950) AND NTIME>=58 THEN J1L*CILADD=( (1. - (. 5+A (1951) ) *DI) / (1 . -. 5*DI) ) *J1L*0ILADD 17 CONTINUE 189 O i l EXPORTS (APPROXIMATE SERIES FROM GRAPH IN NEE (1975) REPORT) IF NTIME=76 THEN OILEXPT=U60. 0 IF NTIME=77 THEN OILEXPT=350.0 IF NTIME>77 THEN OILEXPT=.60*J1I*CILEXPT 2.D EQUATIONS FOR FUEL LOSSES AND ADJUSTMENTS PLUS ENERGY SUPPLY USE 1. EQUATIONS FOR ENDOGENOUS VARIABLES LOSS FOR GAS IN BCF LOSS FOR OIL IN MMBBL LOSS FOR ELECTRICITY IN TRILLIONS KWH LOSSES FOR ELECTRICITY ARE A PROPORTION OF REGIONAL SALES LOSSL. AT-A (2056) * (QL. AT/A (1 922) ) +TEMP (LOSSL. AT) LOSSL. QU=A (2057) * (QL.QU/A (1922) ) + TEMP (LOSSL . QU) LOSSL. ON=A (2058) * (QL, ON/A (1922) ) +TEMP (LOSSL. ON) LOSSL. PP.=A (2059) * (QL. PR/A (1922) ) +TEMP (LOSSL. PR) LOSSL. BC=A (2060) * (QL. BC/A (1922) ) +TEMP (LOSSL. BC) LOSSES FGR CRUDE OIL ARE A PROPORTION OF REGIONAL SALES LOILAT = A (2046) *QO.AT/(A (1955) * A (1921) ) + TEMP (LOILAT) LOILQU=A (2047)*QC.QU / (A (1956) *A (1921)) +TEMP (LCILQU) LOILCN=A (20 50) *QO.ON/ (A (1957) *A (1921) ) +TEMP (LOILON) LOILPR=A (2066) *QC. PR/(A (1958) *A (1921) ) +TSMP (LCILPR) LOILBC=A (2069) *QO. BC/ (A (1959) *A (1921) ) +TEMP (LCILBC) LOILEAST=LOILAT+ LOILQU +TEMP (LOILEAST) LOILWEST=IOILON + LOILPR + LOILBC +TEMP (LOILWEST) LOSSES FOR NATURAL GAS ARE A PROPORTION OF SALES FOR QUEBEC AND ONTARIO; BUT LOSSES ARE A PROPORTION OF PRODUCTION FOR PRAIRIES AND BC LGASQU=A (2074)*QG.QU / (A (1960)* A(1923)) +TEMP (LGASQU) LGASCN=A (2133) *QG.ON/ (A (1981) *A (1923) ) +TEMP (LG A SON) LGASPR=A (2134)* (.843*GASPRO*365.) +TEMP(LGASPR) LGASBC=A (2135) * (. 157*GASPRO*365. ) +TEMP (LGASBC) LOSSGAS=LGASQU + LGASON +LGASPR + LGASBC +TEMP (LOSSGAS) 191 3. Description of the Demand Sector The following description w i l l explain the abreviations and mnemonics that occur throughout the following demand appendicies, especially i n appendix a, B and D. In each of the equations, the parameters are i n lower case and the variables are in upper case. The following, conventions were adapted for structuring the mnemonics for the variables: any two l e t t e r variable beginning with 'S* denotes a share, any two l e t t e r variable beginning with *P' denotes a price, any two l e t t e r variable beginning with 'Q * denotes a guantity, the variable 'C represents t o t a l energy cost, any variable beginning with 'DUM* denotes a regional s h i f t v ariable, 'In* preceding a variable denotes that the variable i s in natural logarithms; any of the share, price or guantity variables ending in * 0 1 denotes crude o i l , any of the share, price or guantity variables ending i n • G' denotes natural gas, any of the share, price or guantity variables ending i n '1* denotes e l e c t r i c i t y , any of the share, price or guantity variables ending in * C denotes coal; any of the variables ending in region, any of the variables ending i n any of the variables ending i n 'AT' denote the A t l a n t i c •QU* •0Nf denote the Quebec region, denote the Ontario region, any of the variables ending i n 'PP.' denote the P r a i r i e region, any of the variables ending in 'BC denote the B.C. region. The following conventions were adapted for structuring the mnemonics for the parameters: any parameter beginning with an 'a' or 'd' i s associated with a regional s h i f t variable, any parameter beginning with a 'b' i s associated with a price variable, any parameter beginning with a *c,* i s associated with the pipeline mile variable, any parameter beginning with an 'e' i s associated with other variable types; any of the 'a' or 'd' parameters that end with associated with the A t l a n t i c region, any of the 'a' or »d' parameters that end with associated with the Quebec region, any of the 'a' or 'd' parameters that end with '3' are associated with the Ontario region, any of the 4a« or ' d' parameters that end with associated with the P r a i r i e region, any of the 'a 1 or 'd 1 parameters that end with associated with the B.C. region; any of the parameters that contain an to* are associated with crude o i l , any of the parameters that contain a 'g' are associated with natural gas, 1 ' are are are 5 1 are 192 any of the parameters that contain an * 1' are associated with e l e c t r i c i t y , any of the parameters that contain a 'c* are associated with coal . The r e s u l t s of a l l of the estimations have been obtained from the TSP program available at UBC . The following abreviations have been used whenever 'an estimation procedure has been reported: log L i s the logarithm of the li k e l i h o o d function, P.2 i s the c o e f f i c i e n t of determination, used to measure the goodness of f i t for the regression, dw i s the Durbin-Watson s t a t i s t i c , used to measure the degree of autocorrelation, rho i s the f i r s t order s e r i a l autocorrelation c o e f f i c i e n t , ser i s the standard error of the regression, Y i s the mean of the dependent variable, nobs i s the number of observation points used in the regression, estimation period i s the h i s t o r i c a l time period for the data, OLS estimation procedure i s the ordinary least sguares technique, i t e r a t i v e Zellner estimation procedure i s a technique used in a multivariate system, which i s eguivalent to maximum li k e l i h o o d estimation, Cochrane- Orcutt estimation procedure i s a technigue used to correct autocorrelated residuals. 193 3.A Derivation of Cost Share Eguations The following derivation i s performed for the main (non-thermal) set cf demand eguations which represent the demand for crude o i l , natural gas, and e l e c t r i c i t y in Quebec, Ontario, P r a i r i e s , and B.C. regions. The derivation for the Atlantic region includes only the demand for crude o i l and e l e c t r i c i t y . The derivation of each of the three sets of a u x i l i a r y (thermal) demand equations i s performed i n an analogous manner. 1. Quebec, Ontario, P r a i r i e s , B.C. equations: The basic translog cost share eguations are as follows: SC = (PO*QO)/C = ao2*DUMQU + ao3*DUM0N + ao4*DUMPR + ao5*DUMBC + boc*ln PO + b'og*ln PG + bol*ln PL + co*GPM SG = (PG*QG)/C = ag2*D0MQU + ag 3*DD MON + ag 4*DU MP R + ag5 •DOMBC + bgo*ln PO + bgg*ln PG + bgl*ln PL + cg*GPM SL = (PL*QL)/C = al2*DUMQ0 + al3*DUMON + al4*DUMPR + al5* DOMBC +blo*ln PO + blg*ln PG + b l l * l n PL + cl*GPM . The r e s t r i c t i o n s imposed upon the parameters of these eguations are as follows: cost shares sum to unity and linear homogeneity in prices boo +bgo +blo = 0 bog + bgg +blg = 0 bol + bgl + b l l = 0 co + eg + c l = 0 ao2 +ag2 + al2 = 1 ao3 + ag3 + al3 = 1 ao4 + ag4 + alU - 1 ao5 + ag5 + al5 = 1 symmetry bog = bgo bol = bio bgl = big . One of the eguations must be dropped from the system during estimation. A r b i t r a r i l y the e l e c t r i c i t y cost share eguation (SL) has been chosen. A l l of the parameters from the omitted equation can be obtained from the constraints: al2 = 1 - ao2 - aq2 a 13 = 1 - ao3 - ag3 al<4 = 1 - ao4 - ag4 al5 = 1 - ao5 - ag5 bio - -boo - bgo big = -bog - bgg = -bgo - bgg b l l = -bol - bgl = boo + bgg + 2*bgo c l = -co - eg . Using the symmetry conditions and line a r homogeneity 194 conditions one can reduce the number of parameters in the two remaining share eguations as follows: bog = bgo bol = -boo - bgo big = -bgg - bgo , Hence one i s l e f t with estimating the following system of two equations: SO = (PO*QO)/C = ao2*DUMQU + ao3*DU'H0N + ao4*D0MPR + ao5*DDMBC + bcc*ln PO + bgo*ln PG + (-boo-bgo)*ln PL + co*GPM SG = (PG*QG)/C = ag2*BUHQU" + ag3*DUMON + ag4*DUMPR + ag5*DCIf5BC + bgc*ln PC + bgg*ln PG + (-bgg-bgc) * l n PL + cg*GPM . The parameters to be estimated are: ao2, ao3, ao4, ao5, ag2, ag3, ag4 f ag5, boo, bgg, bgo, co, eg, 2. Atlantic eguations: The basic translog cost share eguations are as follows: SO •= (PC*QO) /C = ao1*DUHAT + boo*ln PO + bol*ln PL SL = (PL*QL)/C = all*B0MAT + blo*ln PO + b l l * l n PL . The r e s t r i c t i o n s imposed upon the parameters of the eguations are as follows: cost shares sum to unity and linear homogeneity i n prices boo + bio = 0 bol + b l l = 0 ao1 + a l l = 1 symmetry bol = bio . The e l e c t r i c i t y cost share equation (SL) i s dropped, but the parameters of the eguation can be obtained from the estimated parameters as follows: a l l = 1 - ao1 blc = -boo b l l = -bol = boo . Osing the symmetry conditions and the l i n e a r homogeneity conditions the number of parameters i n the estimated eguation can be reduced as follows: bol = -boo . Hence the equation to be estimated has the followinq form: SO = ao1 *DOHAT + boo*ln PO - boo*ln PL , The parameters to be estimated are : ao1, boo. 195 3.B Parameter Estimates of Demand Equations I Equations used for main (non-thermal) demand system 1. Total constant $ expenditure cn primary energy fuels. (a) A t l a n t i c region: The form of the estimated eguation i s as follows: InVE = d1*DUMAT + e1*lnUGNE + e2*ln (jw (PEN/PGNE)) , where VE i s the real value of energy demand, in m i l l i c n s of constant 1961$, DUMAT i s a regional dummy variable for the A t l a n t i c , UGNE i s the re a l value cf gross national expenditure, millions of 1961$, PEN i s the Paasche price index of energy, 1961=1.0, PGNE i s the price index for gross national expenditure, 1961=1.0, jw represents a set of moving weights, with values (.333, . 333, . 333) i . The parameter estimates, with the t s t a t i s t i c i n parenthesis, and eguation s t a t i s t i c s are as follows: d1 -7. 02688 (-1 . 287) R2 = .9515 e1 +1. 1 1905 (2. 188) dw = .738 e2 - . 629771 (1. 012) ser= . 0778 Y = 5.287 nobs = 12 estimation period: 1961-1972 estimation procedure: OLS (b) Quebec, Ontario,.Praires and B.C. regions: The form of the estimated eguation i s as follows: InVE = d2*D0MQU + d3*CUMCN + d4*DUMPR + d5*DUMBC + e1*lnOGNE + e2*ln(jw (PEN/PGNE)), where jw represents a set of moving weights, with values (. 15, . 35, . 35, . 15) . The parameter estimates, with t - s t a t i s t i c i n parenthesis, and eguations s t a t i s t i c s are as follows: d2 -5. 39193 (-12.519) R* = . 8965 d3 -5.2*4249 (-12.080) dw = 1.137 1 When reporting a set of moving weights the convention w i l l be used to place the numbers in brackets, with the f i r s t number being the weight for the current year, the second number for the preceding year, and so on. 196 d4 - 5 . 99389 (-13.81 1) a5 -6.11917 (-14.444) e1 +1. 08334 (27.008) e2 - . 406792 (-4.593) ser = .0277 Y = 6. 190 nobs = 52 estimation period: 1961-1973 estimation procedure: OLS 2. System of cost share eguations (a) A t l a n t i c region: The form of the estimated eguation i s as follows: SO = ao1*DUMAT + boo*lnP0 - boo*lnPL, where SO i s the cost share of crude o i l , DOMAT i s the regional dummy variable for the A t l a n t i c , PO i s the price of crude o i l , $/miilIcn ouptut Btu, PL i s the price of e l e c t r i c i t y , $/million output Etu, both energy prices are a moving weighted average, with weights (.333, .333, .333). The parameter estimates (including parameters from the dropped SL eguation) and eguation s t a t i s t i c s are as follows: (47.008) log L = 21.010 E 2 = . 283 imposed dw = .577 ser = .050 Y = .4 84 nobs = 13 estimation period: 1960-1972 estimation procedure: OLS (b) Quebec, Ontario, P r a i r i e s , and B.C. regions The form of the estimated eguations are as follows: ac1 .652337 a l l .347663 boo .133 bio -.133 b l l .133 SG = ag2*DUMQU + ag3*DUM0N + ag4*DUMPR + ag5*DUMBC + bgo*lnE0 + bgg* InPG + (-bgg-bgo)*lnPL + cg*GPM SO = ao2*DUMQU + ao3*DUM0N + ao4*DDMPE + ao5*DUMBC + boo*lnPO + bgo*lnPG + (-boo-bgo)*lnPL + co*GPM, where SG i s the cost share of natural gas, SO i s the cost share of crude o i l , DUMQU, DDMON, DCMPR, DUMBC are the regional dummy variables, GPM i s the miles of natural gas d i s t r i b u t i o n pipeline, PO i s the price of crude o i l , $/millicn output Btu, PG i s the price of natural gas, $/million output Etu, PL i s the price of e l e c t r i c i t y , $/million outut Btu, each energy price i s a moving weighted average, with weights (. 15, . 35, . 35, . 15). The parameter estimates (including parameters from the dropped SL equation) and eguation s t a t i s t i c s are as follows: 197 ag2 • 0193162 (6. 925) ag3 .0570739 (5.724) ag4 .0642726 (9. 736) ag5 .0130384 (3.183) ao2 .549991 (25.210) ao3 .545368 (23.222) ao4 .594014 (22. 774) ao5 .430827 (15.290) al2 . 4 306 S3 (18.848) al3 .397558 (17.941) al4 .341714 (12. 927) al5 .556134 (18.976) boc . 102982 (2. 994) bgg 0 imposed b l l .102982 (3. 413) bio -.102 982 (3.413) bgo 0 imposed big 0 eg .65738*10- 5 (9.410) CO -.65738*10 i—s c l 0 imposed II Equations used for a u x i l i a r y log L = 88.210 the SO eguation s t a t i s t i c s : R2 •= .891 dw = .678 ser = .0238 Y = .401 nobs = 52 estimation period: 1961-1973 estimation procedure: i t e r a t i v e Zellner the SG eguation s t a t i s t i c s : F.2 = .9712 dw = . 485 ser = .00891 Y = .0851 nobs = 52 estimation period: 1961-1973 estimation procedure: I t e r a t i v e Zellner (thermal) demand system 1, Total current $ expenditure cn primary energy fuels used to generate thermal e l e c t r i c i t y : The form of the estimated eguation is as follows: In TEI$ = d1*DUMAT + d2*DUMQU + d3*BUMON + d4*DUMPR + d5*DUMEC + e1*ln TOTSI$, where TEL $ i s the t o t a l current $ value of energy used i n generating thermal e l e c t r i c i t y , DUMAT, DUMQU, DUMGN, DUMPS, DUMBC are regional dummy variables, TOTSL$ i s the t o t a l current $ expenditure on thermal e l e c t r i c i t y . The parameter estimates and equation s t a t i s t i c s are as follows: d1 .348816 (.735) R2 = .9816 d2 .804297 (1. 951) dw = .539 d3 .516754 (1. 064) ser = .166 d4 .210205 (.430) y = d5 -.127555 (-.281) nobs = 70 e1 .942204 (35. 362) estimation .sriod : 1960-197 3 estimation procedure: OLS 2. System of cost share equations (a) Atlantic and Quebec regions: 198 The fcrm of the estimated equation is as follows: SO = ao1*D0HAT + ao2*DUHQU.- boo*lnPC + boo*lnPO, where SO i s the cost share of crude o i l , DUMAT, DUMQD are regional dummy variables, PC i s the price of coal, $/million output Btu, FO i s the price of crude o i l , $/million output Btu. The parameter estimates (including the dropped SC equation) and equation s t a t i s t i c s are as follows: ao1 ao2 ac 1 ac2 boo bcc 521315 888358 478685 111642 0227315 0227315 (13.470) (23.126) (. 0748) bco -.0227315 loq 1 = 16, R2 = .6524 dw = .219 ser = .142 Y = .704 nobs = 28 estimation estimation 543 period: 1960-1973 procedure: OLS (b) Ontario and P r a i r i e s reqions The form of the estimated equations are as follows: SG = ag3*D0MCN + ag4 *BU MPR + (-bgo-bgg) *lnPC + bgo*lnPO + bgg*lnPG SO = ao3*DUM0N + ao4*DUMPR + (-boo-hgo) *lnPC + boc*lnPO + bgo*lnFG, where SG i s the cost share of natural gas, SO i s the cost share of crude o i l , DUMGN, DUMPR are regional dummy variables, FC i s the price of coal, $/million output Btu, PO i s the price of crude o i l , $/million output Btu, PG i s the price of natural gas, $/million output Btu. The parameter estimates (including parameters from the dropped SC eguation) and equation s t a t i s t i c s are as follows: log L = 11.957 ag3 0750434 (4. 287) SO eguation s t a t i s t i c s : ag4 136416 (1.612) R2 = .4191 ao3 0674516 (4.424) dw = .928 ao4 • 0466713 (4.504) ser = .0267 ac3 « 857502 (30.210) Y = .0485 ac4 816913 (8.709) nobs = 28 - . 141199 (-1. 772) estimation period: 1960-1973 boo — . 147012 (-2.79 7) estimation procedure: i t e r a t i v e Zeliner bcc - .288211 (-2. 446) bgo 0 imposed SG equation s t a t i s t i c s : bco • 147012 (2. 643 ) R2 = .787 beg • 141199 (1.657) dw = .396 ser= . 05 86 199 Y = .174 nobs = 28 estimation period: 1960-1973 estimation procedure: i t e r a t i v e Zellner (c) B.C. region The form of the estimated eguation i s as follows: SO = ao5*D0MBC - boo*lnPG + boo*lnP0 + co*lnGPM, where SO i s the cost share of crude o i l , DUMBC i s the regional dummy avariable for B.C., PG i s the price of natural gas, $/million output Btu, PO i s the price of crude o i l , $/million output Btu, GPM i s the miles of natural gas d i s t r i b u t i o n pipeline miles . The parameter estimates (including those from the dropped SG eguation) and eguation s t a t i s t i c s are as follows: ao1 2.76215 ag1 -1.76215 co -.246464 eg .246464 boo 0 bgg 0 bgo 0 (2.780) (-2.078) imposed log L = 14.