Open Collections

UBC Theses and Dissertations

UBC Theses Logo

UBC Theses and Dissertations

The value of British Columbia’s natural gas used as liquefied natural gas (LNG) for export to Japan Dionne, Francois 1981

Your browser doesn't seem to have a PDF viewer, please download the PDF to view this item.

Item Metadata

Download

Media
831-UBC_1981_A4_6 D05.pdf [ 3.24MB ]
Metadata
JSON: 831-1.0095052.json
JSON-LD: 831-1.0095052-ld.json
RDF/XML (Pretty): 831-1.0095052-rdf.xml
RDF/JSON: 831-1.0095052-rdf.json
Turtle: 831-1.0095052-turtle.txt
N-Triples: 831-1.0095052-rdf-ntriples.txt
Original Record: 831-1.0095052-source.json
Full Text
831-1.0095052-fulltext.txt
Citation
831-1.0095052.ris

Full Text

THE VALUE OF BRITISH COLUMBIA'S NATURAL GAS USED AS LIQUEFIED NATURAL GAS (LNG) FOR EXPORT TO JAPAN b 7 FRANCOIS DIONNE B.A.A. Universite de Montreal A THESIS SUBMITTED IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE DEGREE OF MASTER OF SCIENCE IN BUSINESS ADMINISTRATION i n THE FACULTY OF GRADUATE STUDIES (Graduate School of Busisness Administration) We accept this thesis as conforming to the required standard THE UNIVERSITY OF BRITISH COLUMBIA O c t o b e r 1981 (c) Francois Dionne,1981. In p r e s e n t i n g t h i s t h e s i s i n p a r t i a l f u l f i l m e n t o f the r e q u i r e m e n t s f o r an advanced degree a t the U n i v e r s i t y o f B r i t i s h C o l u m b i a , I agree t h a t the L i b r a r y s h a l l make i t f r e e l y a v a i l a b l e f o r r e f e r e n c e and s t u d y . I f u r t h e r agree t h a t p e r m i s s i o n f o r e x t e n s i v e c o p y i n g o f t h i s t h e s i s f o r s c h o l a r l y purposes may be g r a n t e d by the head o f my department o r by h i s o r h e r r e p r e s e n t a t i v e s . I t i s u n d e r s t o o d t h a t c o p y i n g o r p u b l i c a t i o n o f t h i s t h e s i s f o r f i n a n c i a l g a i n s h a l l n o t be a l l o w e d w i t h o u t my w r i t t e n p e r m i s s i o n . Department o f CO H £ fcC(£1 A^ 3> ~P>0£-SS fS^^VV\\STflPC^C The U n i v e r s i t y o f B r i t i s h Co lumbia 2075 Wesbrook P l a c e V a n c o u v e r , Canada V6T 1W5 DE-6 12/79) i i ABSTRACT The objective of t h i s thesis i s to determine the value of B r i t i s h Columbia's natural gas used as l i q u e f i e d natural gas (LNG) for export to Japan. This value i s calculated by a computer model simulating an LNG project i n B.C. The model s t a r t s with an estimate of the landed price of LNG i n Japan and works backward, costing every step, to the input-end of the p i p e l i n e d e l i v e r i n g the natural gas from the f i e l d to the l i q u e f a c t i o n plant. The value obtained i s the opportunity cost of the natural gas used as LNG and can be compared to the opportunity cost i n other uses and to the cost of supplying the natural gas. We calculate t h i s value for both society and the private firm - the difference accounted for by the p a r t i c u l a r tax structure which would apply to an LNG export project. The base case estimates of the s o c i a l opportunity cost of the natural gas used as LNG range from $3,645 to $4.12 (1981 Canadian dollars) per thousand cubic feet (MCF), depending on the scale of the l i q u e f a c t i o n plant. The estimates of the private opportunity cost are very close to the s o c i a l values - a difference of about 3%. A comparable estimate for the opportunity cost i n use as exports to the United States by p i p e l i n e i s $4.68/MCF although t h i s figure i s based on present and not p o t e n t i a l contracts. A s e n s i t i v i t y analysis i s performed and the c a p i t a l cost and the landed price are found to be the variables with the largest r e l a t i v e impact on the base case estimates. i i i TABLE OF CONTENTS Page I. INTRODUCTION 1 . 1. Statement of the objective of t h i s thesis 1 2. The LNG plant proposals i n B.C. 2 II. ANALYSIS 1. Description of the methodology 5 2. Costs and price estimates 6 a) Pipeline costs 7 b) Liquefaction costs 9 c) Shipping costs 12 -d) C.I.F. price i n Japan 13 3. The computer model 16 a) General working of the computer model 16 b) S p e c i f i c working of each section of the computer model 19 i ) Revenues 19 i i ) Capital costs 19 i i i ) Operating costs 20 iv) Quantity of natural gas used 20 v) . Taxation 20 v i ) Private valuation 23 v i i ) Social Valuation 24 III RESULTS 1. Private and s o c i a l values 25 2. S e n s i t i v i t y Analysis 28 a) Vari a t i o n of the C.I.F. p r i c e i n Japan 29 i v b) V a r i a t i o n o f the Cost E s t i m a t e s i ) C a p i t a l c o s t s i i ) O p e r a ting c o s t s c) V a r i a t i o n i n the assumed v a l u e s o f the parameters IV CONCLUSION Footnotes B i b l i o g r a p h y Appendix 1 O v e r a l l Checks o f the Cost Estimate Appendix 2 E l a b o r a t i o n o f the E q u a t i o n Determinant the p r i v a t e o p p o r t u n i t y c o s t o f n a t u r a l gas used as LNG Appendix 3 The Computer Model L i s t o f t a b l e s L i s t o f f i g u r e s Acknowledgement V LIST OF TABLES J Table 1, Table 2, Table 3. Table 4. Table 5, Table 6. C a p i t a l Cost of the L i q u e f a c t i o n P l a n t Operating Costs L i q u e f a c t i o n P l a n t C.I.F. P r i c e o f LNG i n Japan E s t i m a t i o n of S o c i a l and P r i v a t e Opportunity Costs Present Value o f Q u a n t i t i e s Produced E f f e c t o f Changed C.I.F. P r i c e on the Estimated P r i v a t e and S o c i a l O p p o r t u n i t y Costs Table 7. S e n s i t i v i t y o f P and P t o the Assumed Real Rate of Growth o f €he C.I.F. P r i c e Table 8. S e n s i t i v i t y of P r i v a t e and S o c i a l O p portunity Costs t o Changes i n Assumed C a p i t a l Costs Table 9. E f f e c t o f a V a r i a t i o n o f 1% i n the Assumed C a p i t a l Cost on P and P p s Table 10. S e n s i t i v i t y o f the P r i v a t e and S o c i a l O p portunity Costs t o Changes i n Assumed Operating Costs Table 11. E f f e c t o f a V a r i a t i o n o f 1% i n the Assumed Operating Costs on P^ and P g Table 12. S e n s i t i v i t y o f P and P t o the Assumed Rate of I n f l a t i o n " S Table 13. S e n s i t i v i t y o f P and P; t o the Assumed CCA P Table 14. S e n s i t i v i t y o f P and P t o the Assumed Debt/Eguity R a t i B s Page 9 11 15 26 28 29 31 32 33 34 35 36 37 38 v i LIST OF FIGURES Page Figure 1. Estimation of the Cost Functions 6 Figure 2. ' Private and Social Opportunity Costs 26 VI 1 ACKNOWLEDGEMENT Mr. Paul G. Bradley has been guiding t h i s project from i t s inception; I would l i k e to thank him for his help and patience. Ardo Hanson was very h e l p f u l with the programming. Mr. Trevor Heaver and Mr. B i l l Waters followed the project from the beginning and supplied h e l p f u l comments. Mr. Waters-was the examining committee chairman. I would also l i k e to thank Mr. P. Nemetz for p a r t i c i p a t i n g on very short notice. I. INTRODUCTION N a t u r a l gas was l i q u e f i e d f o r the f i r s t time at the t u r n of the t w e n t i e t h century "...by a combination of compression and c o o l i n g . " 1 The l i q u e f a c t i o n of n a t u r a l gas was i n t e r e s t i n g because of the volume r e d u c t i o n produced by the process; l i q u e f i e d n a t u r a l gas (LNG) o c c u p i e s o n l y l/600th o f i t s o r i g i n a l volume. U n t i l the mid-1960's, n a t u r a l gas was e s s e n t i a l l y l i q u e f i e d o n l y f o r storage purposes and not t r a n s p o r t a t i o n . In the mid-1960's, s h i p s a b l e t o c a r r y v e r y c o l d l i q u i d s were developed. T h i s development opened a completely new use f o r LNG; LNG s h i p s c o u l d now be used t o t r a n s p o r t n a t u r a l gas between two l o c a t i o n s t h a t c o u l d not be e c o n o m i c a l l y l i n k e d by a p i p e l i n e . The p r o d u c t i o n of LNG can thus be viewed as a t y p i c a l case of the impact o f developments i n the t r a n s p o r t a t i o n i n d u s t r y on the v a l u e of the p r o d u c t i o n elsewhere i n the economy. In t h i s s p e c i f i c case, the development i s the new a b i l i t y t o e c o n o m i c a l l y t r a n s p o r t by s h i p v e r y c o l d l i q u i d s , and the impact i s on the v a l u e of n a t u r a l gas i n the ground. 1. Statement of the O b j e c t i v e o f t h i s T h e s i s Many p r o p o s a l s f o r the export of B.C. n a t u r a l gas t o Japan as LNG have come up i n the l a s t year.. These p r o p o s a l s , d e a l i n g w i t h the export o f energy r e s o u r c e s , are a l l s u b j e c t t o Government ap p r o v a l . The debate over these a p p r o v a l s d e a l s w i t h two types o f i s s u e s : the f i r s t i s t o d e c i d e the uses t o which B.C. n a t u r a l gas w i l l be put; the second, a t a more macro l e v e l , i s t o d e c i d e the - 2 -a l l o c a t i o n of c a p i t a l amongst alternate energy projects. In t h i s context, the contribution of t h i s thesis to the debate i s the estimation of the s o c i a l opportunity cost of natural gas used as LNG for export to Japan. Also, we w i l l look at the impact of taxes, as they would apply to an LNG project, on private decisions concern-ing use of natural gas. The opportunity cost i s calculated at the well-head and enters the determination of s o c i a l value of B.C.'s natural gas i n the following way: the s o c i a l value of B.C.'s gas i s the difference between the highest opportunity cost i n use and the s o c i a l cost of extracting the natural gas at the well-head. Putting t h i s d e f i n i -t i o n i n the form of a decision-making rule, we obtain the following: i f we have 0 for the opportunity cost i n use as LNG, 0 for the J_! U , X opportunity cost i n other use X and Cg the cost of supplying the natural gas, an LNG project should go ahead only i f 0 T \ C- v for a l l X and X °L> °S • If these conditions are met, i t w i l l mean that LNG for export to Japan i s the best use for B.C. natural gas and that the necessary c a p i t a l should be allocated to t h i s type of project. We w i l l l i m i t ourselves to the estimation of the opportunity cost i n use as LNG here, t h i s being a s i g n i f i c a n t undertaking of i t s own. Separate studies would be necessary to estimate the value of natural gas i n other uses, and the costs of extracting the gas to the well-head. - 3 -The impact of taxes on private decision-making with reference to the use of B.C. natural gas w i l l be analyzed through the e s t i m a -t i o n of what i s i d e n t i f i e d as the "private opportunity cost of natural gas used as LNG". The private opportunity cost d i f f e r s from the s o c i a l opportunity cost only i n that i t accounts for the tax pay-ments p a r t i c u l a r to an LNG project; the s o c i a l opportunity cost, on the other hand, accounts for the average tax payments which could be expected from other investments of similar size as that required for an LNG project. The private opportunity cost i s the key, i n the decision-making of the private firm regarding the use of natural gas as LNG. A comparison of t h i s value to the s o c i a l opportunity cost w i l l indicate the type of incentive implied i n the tax structure of Canada with regard to the use of natural gas as LNG. For instance, an estimated private opportunity cost far below the estimated s o c i a l opportunity cost may suggest the need for a r e v i s i o n of the tax structure as i t applies to potential LNG pro-jects so that private decision-making s a t i s f i e s the s o c i a l c r i t e r i a (which i s the s o c i a l decision-making rule defined above). 2. The LNG Plant Proposals i n B r i t i s h Columbia As of July 1981, there are four p u b l i c l y known LNG plant proposals i n B r i t i s h Columbia. Each proposal includes an LNG plant as part of a larger scheme focusing on the petro-chemical industry. The four groups involved are: Dome Petroleum, Carter O i l and Gas, 2. Petro-Canada and Westcoast Transmission, and Norcen Energy Resources.. A l l four projects aim at serving the Japanese market and the LNG plant would be located i n the Prince Rupert area i n each case. - A -The feedstock for these plants would come from f i e l d s north of Fort St. John, a distance of about 500 miles. The international^LNG market i s aware of these plans i n B.C. as a mention of them i s made i n the 1980 Petroleum Economist's 3 survey of t h i s market. Despite the general knowledge of these plans, one important element remains unclear. I t i s d i f f i c u l t to i d e n t i f y the pro-\ jected size of these LNG plants. The size of each plant i s gener-a l l y measured i n m i l l i o n cubic feet per day (MMCF/D). The Petroleum Economist's report refers to a 400 MMCF/D plant for A 5 Dome Petroleum. An a r t i c l e i n The Province newspaper announced plans for a 250 MMCF/D plant by Petro-Canada and Westcoast Transmission, with possible expansions to 760 MMCF/D and 1,200 MMCF/D. P r e - f e a s i b i l i t y studies done fo r Carter O i l and Gas 6 consider plants of 250 and 500. MMCF/D. A l l of these schemes suggest a 20 year contract with d e l i v e r i e s s t a r t i n g i n the l a t t e r part of 1986. The apparent indecision regarding the plant capacity may be related to the uncertainty of the c a p i t a l cost estimates. The indication seems to be that the proponents would be w i l l i n g to bui l d a small scale plant, foregoing p o t e n t i a l economies of scale, to obtain more information about the c a p i t a l cost involved. The public strategy of Petro-Canada most c l e a r l y represents t h i s strategy. The group f i l e d a "pre-application" with the B.C. government for a 250 MMCF/D plant and a "planned" expansion to ; 760 MMCF/D with an "option" f o r an ultimate 1,200 MMCF/D.7 The expansion to 760 MMCF/D (and probably even the expansion to - 5 -1,200 MMCF/D) has not been delayed i n the prospect of an improv-ing Japanese market since the Japanese are looking r i g h t now for o over 3,000 MMCF/D of new LNG d e l i v e r i e s . The reason for the delay i s thus l i k e l y to be found on the supply side where the proponents either f e e l that the " s o c i a l value" of the present reserves of natural gas i s too large for the government to accept a long-term export commitment t h i s large, or the firms do not want to get involved i n large scale projects of such c a p i t a l intensiveness without'more information. Our analysis should provide useful information i n the l a t t e r context. II ANALYSIS 1. Description of the Methodology The s o c i a l and private opportunity costs are estimated by a computer model simulating an entire LNG project, from the i n -put end of the p i p e l i n e d e l i v e r i n g the natural gas to the l i q u e -f a c t i o n plant to the dock i n Tokyo, Japan. The computer model starts with an estimate of the landed p r i c e of LNG i n Japan and works backward, costing every step, to the well-head. The study does not investigate various environmental impacts of an LNG project. This would e n t a i l a substantial study i n i t s own rig h t ; there i s considerable uncertainty as to what type of impacts are l i k e l y and the monetary value to assign to these impacts. I f environmental e f f e c t s were found to be s i g n i f i c a n t , they would have to be added to the estimate of s o c i a l costs calculated here. In addition to the estimation of the private and s o c i a l opportunity costs defined here, the model i s also used to perform a s e n s i t i v -i t y analysis. The purpose of the s e n s i t i v i t y analysis i s to - 6 -i d e n t i f y the variables that have the largest r e l a t i v e impact on the estimated opportunity costs. 2. Cost and Price Estimates For modelling purposes, the LNG project has been divided into three components: the pip e l i n e ; the l i q u e f a c t i o n plant i n -cluding storage and port f a c i l i t i e s ; and the ships. For each component, c a p i t a l and operating cost functions were estimated,. It proved d i f f i c u l t to f i n d cost estimates i n the l i t e r a t u r e ; the amount of information c o l l e c t e d i s r e l a t i v e l y meager. Since the data were limited, i t was impossible to apply sophisticated estimation methods e.g., econometrics; so a very simple method was used. The cost functions are simply a set of straight l i n e s l i n k i n g the cost observations gathered. The following graph i l l u s t r a t e s t h i s method: Figure 1 Estimation of the Cost Functions c o s t / x observation #3 on #2 Obviously, we can expect such cost functions to be only rough estimates but i t seems that t h i s r e f l e c t s the incomplete state of knowledge i n the industry about the costs involved. - 7 -The s e n s i t i v i t y analysis w i l l permit one to i d e n t i f y the cost elements that are the most important sources of v a r i a t i o n i n the estimated s o c i a l and private opportunity cost; t h i s information should be used to manage e f f o r t s directed at the refinement of the assumed cost functions.. a) P i p e l i n e Costs The pipeline i s the one component of the project which i s the l e a s t exotic. S t i l l , we are dealing with very rough t e r r a i n and cost functions estimated i n the south-eastern U.S. cannot be expected to apply. The pi p e l i n e envisaged here w i l l run about 500 miles from just north of Fort St. John to Prince Rupert. We are considering volumes upward from 290 MMCF/D, becaiise.it takes 1.16 MCF of natural gas to produce one MCF of LNG, the 0.16 MCF being required as f u e l for the l i q u e f a c t i o n plant. With these volumes, i t seems most l i k e l y that a new pipe-q l i n e w i l l have to be b u i l t over the e n t i r e distance. The estimation of the c a p i t a l cost function i s based on three obser-vations; Capacity Cost per Mile n . 10 Cost (1981 Can.Dol.) Project ' 290 MMCF/D $0 .7 MM (1979 Can.Dol.) $0,847 MM Carter"'"''' 576 MMCF/D $1 .16 MM (1979 Can.Dol.) $1.4036 MM 12 Carter \?> 1200 MMCF/D $1 .28 MM (1976 U.S.Dol.) $2.4737 MM AlgeriaJX (ARZEW) Using t h i s method, the c a p i t a l cost function obtained i s the following: Let x be the c a p i t a l cost of the p i p e l i n e i n $ M i l l i o n - 8 -(1981 Can.Dol.) and y be the capacity of the pipeline i n MMCF/D; i f (y<290), x = 500 (y * .0029206) i f (290<L y <.580) , x = 500^.847 + (y - 290)* .0019193] i f (y>580), x = 500^1.4036 + (y - 580)* .0017259] The estimation of the operating cost function poses a problem i n that the operating costs of a pipeline include the natural gas used as f u e l for the compression stations. This means that the operating cost observed i s s t r i c t l y dependent on the price charged the operator of the pipeline for t h i s f u e l . This i s a problem since we are t r y i n g to figure out what t h i s p r i c e should be. This problem could be circumvented i f we could f i n d a formula defining the r a t i o of the quantity of f u e l to the quan-t i t y moved; with t h i s r a t i o , the operating cost could simply remain i n quantity (and not value) terms and s t i l l be treated 14 endogeneously. But the operation of a pipeline involves two di f f e r e n t margins (diameter and pressure) which makes i t impos-s i b l e to define such a r a t i o . A pip e l i n e of a larger diameter w i l l require less pressure (and thus less fuel) to move a given quantity of natural gas. Also, the operating costs of a p i p e l i n e involve a r e l a t i v e l y small amount of money as i t i s a very c a p i t a l intensive proposition. The assumed operating cost i s based on figures from an 15 N.E.B. rate hearing. The annual operating costs of ICG Transmission Ltd., from the statements presented at t h i s hearing are estimated at $0.081931 (1979 Can.Dol) per MMCF per mile or $59,976 (1981 Can.Dol.) per MMCF for a 500 mile p i p e l i n e . - 9 -To get an idea of the r e l a t i v e s i z e of t h i s number, for a 250 MMCF/D plant t h i s works out to about s i x m i l l i o n (1981 Can.Dol.) a year or about $0.06 (1981 Can.Dol.) per MCF. In other words, even i f ICG Transmission paid only h a l f of the s o c i a l value of B.C. gas, we would get an overvalue of only 60 per MCF, representing an "anticipated margin of error of 1.5%. We w i l l come back to t h i s subject i n the s e n s i t i v i t y analysis. Using the value mentioned above, the operating cost function i s : y = $59,976 * capacity * number of operating days i n a year, where y i s the annual operating cost. b) Liquefaction Costs a l l the f a c i l i t i e s required between the output-end of the pipe-l i n e and the ships. These f a c i l i t i e s constitute a complex system which i s not analyzed i n d e t a i l here. We use the t o t a l reported project cost of ex i s t i n g or planned f a c i l i t i e s f or the purpose of estimating our cost function. The c a p i t a l cost function has been estimated with three observations: Table 1 The l i q u e f a c t i o n plant as defined here includes Capital Cost of the Liquefaction Plant Capacity Cost ($Million) Cost ($Million) (1981 Can.Dol.) Proj ect 250 MMCF/D $366 (1979 Can.Dol.) $442 Carter O i l and Gas 16 500 MMCF/D $571 (1979 Can.Dol.) $929 (1980 Can.Dol.) $691 Carter O i l and Gas 17 1000 MMCF/D $1022 Example froi the l i t e r a -ture - 1 0 -Using our simple estimation method, the c a p i t a l cost function obtained from these observations i s the following; l e t t i n g x be the c a p i t a l cost i n $ M i l l i o n (1981 Can.Dol.) and y the capacity i n MMCF/D, i f Y<250, x = y * 1.768 i f 250<y<500, x = 442 + £_(y - 250)^* .996^ i f y> 500, x = 691 +"Q(y - 500) * .662^] The l i q u e f a c t i o n plant i s the component of the project where we f i n d the greatest uncertainty as to the l e v e l of the c a p i t a l costs. While natural gas p i p e l i n e s are f a i r l y common and there e x i s t s an i n t e r n a t i o n a l market with strong competition f o r LNG tankers, the LNG plants must be costed i n d i v i d u a l l y . The plant i s i n f a c t a complex set of buildings and equipment and the cost of erection depends on l o c a l factors, e.g., l o c a l construction's i n f l a t i o n rate, i s o l a t i o n of the plant, etc. Considering t h i s , our estimated c a p i t a l cost function seems to represent the state of the knowledge of the p a r t i e s involved i n B.C. This f a c t underlines the importance of the s e n s i t i v i t y analysis for t h i s p a r t i c u l a r element of the t o t a l cost; indeed, i t i s more important to know how the value of the natural gas varies with the c a p i t a l cost of the l i q u e f a c t i o n plarvi. then to know "t-We. value given a point estimate of the c a p i t a l cost. The operating cost of the l i q u e f a c t i o n plant i s much easier to deal with because i t e s s e n t i a l l y consists of the f u e l i n a well-accepted approximated r a t i o . I t i s held as heneral knowledge that i t takes about 1.16 CF of natural gas to produce 1 CF of LNG, 0.16 CF being required as f u e l . This aspect of the operating cost i s thus treated endogene-- 11 -o u s l y i n the formula d e t e r m i n i n g the v a l u e o f t h e n a t u r a l cjas. The r e m a i n i n g p a r t o f t h e o p e r a t i n g c o s t has been embodied i n an e s t i m a t e d f u n c t i o n u s i n g the same method a g a i n . We have t h r e e o b s e r v a t i o n s : T a b l e 2 O p e r a t i n g C o s t s L i q u e f a c t i o n P l a n t C a p a c i t y (MMCF/D) C o s t (MM) Cos t MM P r o j e c t (1981 C a n . D o l . )  250 $13 (1979 C a n . D o l . ) $15.73 C a r t e r 0 i £ 0 and Gas $21 $25.41 C a r t e r O i ^ (1979 C a n . D o l . ) and Gas $27 $43.12 Example (1978 U . S . D o l . ) from t h e 2 2 l i t e r a t u r e 500 1000 From t h e s e o b s e r v a t i o n s we e s t i m a t e the f o l l o w i n g annua l o p e r a t i n g c o s t f u n c t i o n : l e t t i n g x be the a n n u a l o p e r a t i n g c o s t i n $ M i l l i o n (1981 C a n . D o l . ) and y t h e c a p a c i t y i n MMCF/D: i f y < 2 5 0 , x = y * .06292 i f 2 5 0 < y < 5 0 0 , x = 15 .73 + £ ( y - 250) * .03872^ i f y > 5 0 0 , x = 25.41 + £ (y - 500) * . 03542^ T h i s p a r t o f the o p e r a t i n g c o s t i s r e l a t i v e l y s m a l l , about $0 .16 (1981 C a n . D o l . ) p e r MCF o r 4% o f t h e t o t a l v a l u e , so we w i l l n o t d i s c u s s t h i s e s t i m a t e f u r t h e r b u t s i m p l y i n c l u d e i t i n t h e s e n s i t i v i t y a n a l y s i s and p e r f o r m an o v e r a l l check on t h e t o t a l c o s t o f l i q u e f a c t i o n ( append ix "1) t o s a t i s f y o u r s e l v e s t h a t t h e c o s t e s t i m a t e s a r e " i n the b a l l p a r k . " / - 12 -c) Shipping Costs The estimation of the costs of shipping involves a set of problems very d i f f e r e n t from those encountered with the pipeline or l i q u e f a c t i o n . In t h i s case there are no econom-ies of scale because the shipbuilding industry produces almost exclusively a standard size LNG tanker-125,000 cubic meters 3 (m ), 4-4,143 gross tons. The problem thus s h i f t s to the determination of the cost of each tanker and of the number of tankers required. 3 The cost of a 125,000 m tanker has been set for the base 23 case a $225 MM (1981 Can.Dol.). A f i r s t source quotes a range for the c a p i t a l cost of $115 MM to $155 MM (1979 U.S.Dol.). I use the figure of $155 m i l l i o n (1979 U.S.Dol.) because other 24 sources quote prices more i n l i n e with the upper part of th i s range. In fact, at present there i s over-capacity i n the LNG tanker b u i l d i n g industry so that the most important factor i n the v a r i a b i l i t y of the estimates i s the amount of governmental subsidization i n shipbuilding. The c a p i t a l cost function i s thus simply: x = (y/36430) * 225, where x i s the cost i n $mi l l i o n (1981 Can.Dol.) and y i s the t o t a l annual production i n MMCF. The parameter "36,430" i s obviously the key to t h i s function. The perspective taken i s that the shipping capacity has to equal the production capacity on a yearly basis. The capacity of a., ship times the number of return t r i p s t r a v e l l e d i n a year i s 36430 MMCF. The detailed c a l c u l a t i o n i s presented below: - 13 -1 cubic meter = 21,885 Cf 125,000 m3 = 2,735.6 MMCF 25 number of t r i p s i n a year =13.32 t o t a l capacity of a ship = 36430 MMCF. The c a p i t a l cost function has been made li n e a r to deal simply with the fact that shipping capacity must somehow equal production capacity over a long enough period of time. This cost equation should be r e l i a b l e because i t rests on a sound estimate of the cost; s e n s i t i v i t y analysis w i l l deal with the v a r i a b i l i t y introduced by the governmental subsidization i n shipbuilding. As was the case for the l i q u e f a c t i o n , the operating cost of the ships i s considered i n two parts: f u e l and other costs. Most of the fu e l originates i n b o i l - o f f of the LNG. On the ret u r n - t r i p to Japan, the b o i l - o f f i s of the order of 5% of 2 6 the capacity. This aspect of the operating cost i s treated eniogeneousLy i n the formula determining the value of the natural gas used. The remaining part of the operating costs w i l l be set equal to the detailed estimate provided by the U.S. govern-27 ment of $38MM (1976 U.S. Dol.) for s i x ships on the E l Paso Project. This estimate works out to a $12.24 MM (1981 Can.Dol. annual operating cost per ship and the cost function becomes: x = (y/36430) * 12.24 where x i s the annual operating cost i n $million (1981 Can.Dol.) and y i s the annual production d) C.I.F. Prices i n Japan We need to estimate a C.I.F. s p e c i f i c to t h i s project because there i s no inte r n a t i o n a l p r i c e f o r LNG, s i m i l a r to the world o i l price, that can be used as a general reference. - 14 -While natural gas and o i l are considered substitutable fuels by many, prompting i l l o g i c a l requests for BTU p a r i t y 2 8 of prices, they are very d i f f e r e n t products i n terms of marketing. In fact, there i s no marketplace where natural gas i s traded; thus, for example, we do not have such a thing as a spot price for natural gas equivalent to the spot p r i c e of o i l . This i s because of the c o s t l y i n f r a s t r u c t u r e required to carry through a natural gas purchase agreement; i n most cases t h i s i n f r a s t r u c t u r e takes the form of a p i p e l i n e , as 29 over 95% of the world's gas consumption i s pipelined. An LNG project allows more f l e x i b i l i t y than a p i p e l i n e but s t i l l requires s p e c i a l i z e d port f a c i l i t i e s . The f a c t that suppliers and buyers have to be linked through an expensive i n f r a s t r u c t u r e means that the flow of natural gas can only be changed at a high cost which e f f e c t i v e l y prevents the working of a market. In addition to the l i m i t a t i o n s i t poses on the working of a market, natural gas i s found i n reserves widespread around the world which, i n a c t u a l i t y , makes i t impossible for a group of supplying countries to dominate the gas sales and set p r i c e s . In t h i s context, one should not be surprised by the large spread i n the prices at which natural gas i s traded around the world. For instance, i n 1979, "the Netherlands (the world's biggest i n t e r n a t i o n a l supplier) r e a l i s e d C.I.F. prices ranging from $1.25 - 3.65 m i l l i o n BTU on f i v e d i f f e r e n t markets. - 15 -Each trade agreement involves i n f a c t a negotiated price. The r i g h t price to use i n evaluating B.C.'s gas used i n LNG exports to Japan i s thus the price that the Japan-ese pay for t h i s type of product i . e . , we can l i m i t our attention to the Japanese LNG imports. It i s a well-known fa c t that Japan depends heavily on 31 imported energy - for about 98% of i t s t o t a l supplies. The Japanese purchasing p o l i c y has stressed d i v e r s i f i c a t i o n of products and sources. LNG i s one of the numerous products 32 and i t i s already supplied from four d i f f e r e n t sources. In addition, t a l k s are now i n progress with f i v e new sources 33 besides Canada. In t h i s perspective, i t i s not l i k e l y that Canada w i l l be able to draw a great advantage from playing i t s "security of supply" card. A reasonable assumption i s to expect a p r i c e equal to the weighted average of the current Japanese C.I.F. prices, since t h i s weighted average already r e f l e c t s the Japanese need for d i v e r s i f i c a t i o n i n t h i s period where more countries are w i l l i n g to agree to LNG trading. The weighted average has been calculated at $7.38 (1981 Can.Dol.) per MCF. The data follow: Table 3 C. I.F.Price of LNG i n Japan Source Price Date Price Quantity . (1981 Can.Dol.) (MMCF/D) Abu Dhabi $5.75 U.S. Sept'80 7.84 240 3 4 Alaska $4.93 U.S. Aug.'80 8.086 105 3 5 Brunei $5.21 U.S. Aug.'80 7.104 774 3 6 Indonesia $5.43 U.S. Aug. '80 7.404 1 1 4 5 5 7 ' 3 8 \ 3. The Computer Model We review the model by looking f i r s t at i t s general functioning. We then look i n d e t a i l at each section of the model. a) General Working of the Model The model works on an annual basis. It i s i n i t i a t e d i n 1981 and terminated i n 2005. The f i r s t f i v e years (1981-1985) are construction years and the plant operates for 20 years from 1986 to 2005. A l l annual revenues and costs are assessed at the end of the year i n the current year's d o l l a r s . We need to use current d o l l a r s because of our intent to id e n t i f y the impact of the tax structure, as i t applies to an LNG project, on the decision-making i n the use of natural gas. In c a p i t a l intensive projects, the c a p i t a l cost allow-ance (CCA) i s an important determinant of the tax payments due; the CCA i s based on h i s t o r i c a l costs, so i t s impact on the tax payments varies with the i n f l a t i o n rate. In the base case, the rate of i n f l a t i o n is. pegged at 10% per annum. Dol-l a r s of d i f f e r e n t years are compared using an estimate of the rate of s o c i a l time preference; the nominal rate of s o c i a l time preference (STPNOM) i s equal to (1 + re a l S.T.P.) * (1 + rate of i n f l a t i o n ) . The choice of a discount rate i s a very contentious issue. In Baumol's words, "few topics i n our d i s c i p l i n e r i v a l the s o c i a l rate of discount as a subject exhibiting simultaneously a very considerable degree of know-39 ledge and a very substantial l e v e l of ignorance." There exists a considerable degree of knowledge because, "economists understand thoroughly just what t h i s variable ( s o c i a l rate of discount) should measure: the opportunity cost of postponement of receipt of any benefit yielded by a public investment. Despite t h i s basic understanding, two fundamentally d i f f e r e n t approaches to the estimation of the rate of discount have emerged. A f i r s t one advocates the use of the s o c i a l rate of time preference (S.T.P.) while the second proposes the use of the opportunity cost of the c a p i t a l invested. As Baumol mentions, these two approaches w i l l never y i e l d the same estimate because of the presence of taxes; the S.T.P. i s estimated by the after-tax rate of return on investment, while the opportunity cost i s usually estimated by the before-tax rate of return. 4 - 1 According to E.J. Mishan, the appropriate approach depends on the public investment to be analysed. Where the public investment i s financed from postponed consumption and the money.raised can only be used for t h i s s p e c i f i c investment (because of some p o l i t i c a l or administrative constraints), the S.T.P. i s the appropriate approach. The S.T.P. w i l l ensure, that the rewards from the public investment w i l l at le a s t compensate the postponed consumption and that the project w i l l go ahead i f i t more than compensates f o r t h i s postponed con-sumption. (Viewed i n t h i s way, the S.T.P. approach i s only a special case of the opportunity cost approach, which agrees with Baumol 1s statement that economists understand thoroughly what i s to be measured.) - 18 -4 ? Again according to Mishan," i n any cases where the money raised for a public investment could be rechannelled towards the private sector, the appropriate approach i s the opportun-i t y cost of c a p i t a l . This approach e n s u r e s that society wi." at least be compensated for the foregone private investment. There i s an hybrid approach consisting of a weightecl a^ ,» of the S.T.P. and the opportunity cost which applies i n cases where money i s raised for a s p e c i f i c project by reducing con-sumption and private investment. We opted for the S.T.P. approach, estimated by the a f t e r -tax rate of return on private investment, because of the par-t i c u l a r c h a r a c t e r i s t i c s of the project to be analysed. An LNG project, l i k e the other proposed "energy mega-projects", would proceed i n close cooperation with the Government. The STP i s a uniform rate which Government can apply across diverse industries with d i f f e r e n t degrees of r i s k and tax rates. The average, after-tax rate of return on c a p i t a l i n Canada has been estimated by John F. H e l l i w e l l at 7 . 5 % ( r e a l ) . The c a l c u l a t i o n of present values, or the actual compar-ison of d i f f e r e n t years' d o l l a r s , i s done i n two steps. F i r s t we find the t o t a l value i n do l l a r s of the f i n a l year of the project in t h i s way: t o t a l current value = (total current value at the end of the previous year * STPNOM) + this year's value or, y = y , *STPNOM + x where x i s the value of y for t.~ 1 the current period. When the current year i s the f i n a l year, the t o t a l current value i s equal to the t o t a l value (costs or revenues) i n - 19 -d o l l a r s of that year; second, we take t h i s l a s t year value and divide by a discount factor equal to STPNOM at the power (l a s t year - f i r s t year of construction), e.g. 2005-1981. This produces a present value for the stream of revenues or costs (this procedure i s also applied to quantities to get a present value i n volume for a flow of quantities, either consumed or produced). There are other ways to calculate present values but t h i s one has been chosen and w i l l be used every time a present value i s calculated. b) S p e c i f i c Working of Each Section The model can be divided i n seven sections: revenues, c a p i t a l costs, operating costs, natural gas,used, taxation, private valuation and s o c i a l valuation. Each section w i l l be reviewed i n d i v i d u a l l y . Of course, the general working rules of the model apply to every section. i ) Revenues The C.I.F. price of LNG i s assumed constant i n re a l terms. It i s thus revised annually to increase at the rate of i n f l a t i o n . The plant i s assumed to be i n operation 340 days a year, operating at f u l l capacity and 100% of the produc-t i o n i s sold under contract. The determination of the quantity sold allows for the en-route b o i l - o f f . The annual revenues are simply the product of quantity sold and price i n d o l l a r s of the year. The present value of revenues i s calculated. i i ) Capital costs The cost function estimated i n the previous section gives an estimate of the c a p i t a l costs i n 1981 Can.Dol. The - 20 -cal c u l a t i o n of the actual amount invested s t a r t s with t h i s estimate and allows for the construction schedule and i n -43 f l a t i o n . The construction schedule has been f i x e d as 44 follows; pipeline: 33% i n plant: 20% i n ships: 33% i n 1983 1982 ' 1983 34% i n 30% i n 34% i n 1984 . 1983 , 1984 33% i n 40% i n 33% i n 1985 1984 1985 10% i n 1985 The financing of t h i s investment follows a debt-equity r a t i o of 60/40 with both debt and equity bearing a r e a l cost of c a p i t a l of 7.5% per annum. The debt i s repaid on equal annual instalments over twenty years. The economic depreciation, as opposed to the c a p i t a l cost allowance, follows a str a i g h t l i n e over twenty years; i n other words, we assume that the c a p i t a l stock l a s t s twenty years and i s worn out evenly throughout these years. i i i ) Operating costs The treatment of operating costs i s very s i m i l a r to that of the c a p i t a l costs. The cost functions produce estimates of annual costs i n 1981 Can.Dol. which are then adjusted for i n f l a t i o n to produce the current annual operating costs. It must be noted that only the d o l l a r costs are consi-dered here, which excludes the natural gas used as f u e l for the l i q u e f a c t i o n plant and the ships; t h i s f u e l i s treated i n quantity terms. - 21 -iv) Quantity of natural gas used We want to determine here how much gas i s necessary to generate the figures produced by the model. Since our objective i s to figure out the value of B.C. gas i n t h i s use, i t i s e s s e n t i a l to be clear as to the quantity of•gas used i n every case studied. The amount we are looking for can be v i s u a l i z e d simply as the quantity of natural gas purchased annually by the operator of the e n t i r e project from the B.C. Petroleum Corporation. This amount equals: annual capacity times 1.16, where the annual capacity i s as described i n the revenues section. v) Taxation The plant envisaged here i s a "transformation plant" which i s not involved with exploration or extraction of natural resources. It i s thus taxed l i k e a"normal" manufacturing plant despite i t s natural resources intensiveness i . e . , i t i s not subject to any kind of d i r e c t royalty payment. The taxes for a "normal processing plant" i n B.C. are: 13% of taxable income as p r o v i n c i a l taxes 36% of taxable income as federal taxes, with the same 4.5 taxable income i n both cases. The taxable income i s defined by the following equation: taxable_ R e v e n u e s _Capital _ Cost of_ Operating _ Cost of income ~ Cost Debt Cost Natural Allowance Gas. Revenues, cost of debt, and operating have been discussed e a r l i e r . The c a p i t a l cost allowance (CCA) i s the "taxation - 22 -analogue" of the economic depreciation;in general terms, i t i s an accelerated depreciation allowed for taxation purposes as an investment incentive. Each year, the CCA w i l l be equal to an allowed percentage of a declining balance, s t a r t i n g with the year when the investment i s made without' regard as to whether or not i t i s a c t u a l l y operated i n that year; the allowed percentage i s determined by the nature of the invest-ment with d i f f e r e n t types of investments being grouped by classes. In the case of the LNG project, I i d e n t i f i e d f i v e classes which are shown below with t h e i r allowed rate: p i p e l i n e : 6% building: 5% machinery: 20% tank: 10% 46 ship: 15% The t o t a l investment has been divided between these classes i n the following proportions: pi p e l i n e : . .. ' 100% "pipeline" l i q u e f a c t i o n plant: 20% "storage tanks" 20% "building" 60% "machinery" ships: 100% "ships". 'In c a l c u l a t i n g the actual tax payment related to the project, the hypothesis i s made that the firm has a large taxable income r e l a t i v e to the c a p i t a l cost allowances derived from investment i n the LNG Project: It i s most u n l i k e l y that a small corporation would go alone i n a project of t h i s size -requiring an investment of over $1.5 b i l l i o n (1981 Can.Dol.). - 23 -Indeed, i t i s most l i k e l y that at least one large firm, with a large immediate cash-flow, w i l l get involved so that the tax savings w i l l be used as soon as they occur. The net value of the tax payments i s calculated according to the following equation: net value of tax present value present value of the payments(in pres- = of tax - average tax payments on ent value) payments the amount of c a p i t a l invested. The average tax payments have been estimated for Canada by John F. H e l l i w e l l at 3% (real) of the c a p i t a l invested. This equation accounts for the fact that projects requiring the same amount of c a p i t a l can produce streams of tax payments having a d i f f e r e n t present value because of the structure of the c a p i t a l cost allowances. In t h i s perspective, the present value of the average tax payments i s a measure of the oppor-tunity co,st, to the government, of the c a p i t a l invested i n LNG projects. v i ) Private Valuation The estimation of the private opportunity cost of the natural gas used as LNG s t a r t s with t h i s technical d e f i n -i t i o n of opportunity cost: i t i s that price for the natural gas that w i l l make the present value of the project equal to zero for the firm. From t h i s d e f i n i t i o n , we derive the basic equation estimating the private value: PV of the project = 0 , and expand i n the following way: PV (Revenues) - PV (Cost) = 0 , or PV (Revenues) - PV ( A l l Cost Except = PV (Cost of Natural Natural Gas) Gas) And PV (Cost of Natural Gas) = ^ Qp*r f*<x ^ Q Pp * cV_ b1 b*4 - 24 -where Qp i s the quantity purchased annually, a i s the annual rate of increase i n the i n i t i a l Price (P ) and b i s the P annual rate of discount. ( i . E . b = (1 + STP) * (1 + i n f l a t i o n ) ) We can i s o l a t e P from t h i s series and c a l l the remaining P part A, so that; Pp = PV (Revenues) - PV (Of a l l cost except Natural Gas] A . • The d e t a i l e d f i n a l equation, l i n e s 274 to 249 of the computer model, and i t s elaboration are shown i n Appendix 2. v i i ) Social Valuation The equation estimating the s o c i a l value was derived i n a s i m i l a r way to the equation for the private value. So we can proceed more ra p i d l y .in t h i s case, e s s e n t i a l l y high-l i g h t i n g the differences. We have PV (Revenues) - PV (Social Cost) = PV (Natural Gas) or PV (Revenues) - PV (Cap. Cost) - PV (A.R-.G.) - PV (Op. costs) = Z, then, Z = PV (Natural Gas), and Z = P V ( Q * P * s ) , so that p s PV (Revenues)-PV(Cap.Costs)-PV(A.R.G.)-PV(Op.Costs) * 1 PV(s) s' Q P the s o c i a l value i n 1981 Can.Dol, where PV( S) = (1+STP) 2 0 *•(1+P.I.) 5 - (1+P.I.) 2 5 (1 + S T P ) 2 5 - (1+STP.)2^ *• (1+P.I.) - 25 -The s o c i a l value i s thus expressed i n a manner s i m i l a r t o the p r i v a t e v a l u e . We m u l t i p l y by 1000 to get a f i g u r e i n 1981 Can.Dol./MCF. As was mentioned i n the i n t r o d u c t i o n t h i s v alue i s of l i t t l e use by i t s e l f but i t has a s i g n i f i c a n t p o t e n t i a l importance when used i n the proper context. , I t can p l a y the dual r o l e o f h e l p i n g t o determine the opportun-i t y c o s t o f B.C. gas, and to estimate the s o c i a l value o f an LNG p r o j e c t g i v e n t h i s o p p o r t u n i t y c o s t . We w i l l not t u r n t o the a c t u a l c a l c u l a t i o n o f these p r i v a t e and s o c i a l v a l u e s (P and P ). • P s I I I RESULTS In t h i s s e c t i o n we w i l l p resent our base case estimates of the s o c i a l o p p o r t u n i t y c o s t o f n a t u r a l gas used as LNG (P ) and estimates of the p r i v a t e o p p o r t u n i t y c o s t o f t h i s n a t u r a l gas (P ). We w i l l a l s o perform a s e n s i t i v i t y a n a l y s i s on these estimates with the o b j e c t i v e o f i d e n t i f y i n g the r e l a -t i v e impact o f the d i f f e r e n t p o t e n t i a l sources o f v a r i a t i o n i n the estimates. 1. P r i v a t e and S o c i a l Values The p o i n t e s t i m a t i o n of P ( p r i v a t e o p p o r t u n i t y c o s t ) and P g ( s o c i a l o p p o r t u n i t y c o s t ) r e p r e s e n t our base case. The e s s e n t i a l parameters and t h e i r v a l u e s , determining t h i s base case are l i s t e d below; - 26 -- C.I.F. Price: $7.38 1981 Can.Dol./MCF - annual rate of i n f l a t i o n : 10% - r e a l rate of increase of P , P and the C.I.F. price: 1 p s ^ (referred to' as the "price i n f l a t o r " ) - cost figures: as estimated by the relevant cost functions - debt/equity r a t i o : 60/40 P and P were estimated for four d i f f e r e n t plant sizes, s p ^ ' from the smallest to about the largest envisaged, 250, 500, 750 and 1000 MMCF/D. The res u l t s follow; Table 4 Estimation of Social and Private Opportunity Costs Plant Size P p (1981 Can.Dol.)/MCF Pg(1981Can.Dol.)/MCF 250 500 750 1000 3.751 4.008 4.144 4.212 3.645 3.908 4.049 4.120 These r e s u l t s can be e a s i l y graphed for a continuous approximation: P g, P p (1981 Can.Dol./MCF) 00 •^.50 Figure 2 Private and Social Opportunity Costs 250 5 0 C ix. \ DO O - 27 -These res u l t s present i n a tangible way the economies of scale involved i n an LNG project; the private and s o c i a l values depend s i g n i f i c a n t l y on the siz e of the commitment accepted. On one hand the firm can pay B r i t i s h Columbia Petroleum Corporation up to $0,461 (1981 Can.Dol.) per MCF more i f i t i s w i l l i n g to commit the c a p i t a l necessary for a 1000 MMCF/D plant versus a 250 MMCF/D plant. S i m i l a r l y , society can get up to $0,475 (1981 Can.Dol.) per MCF more for i t s natural gas i i f i t i s ready to commit the quantities of natural gas neces-sary to feed a 1000 MMCF/D plant versus a 250 MMCF/D plant over 20 years. This question of commitment has to do with what was pres-ented as the probable strategy of the present proponents of a B.C. LNG plant. I t i s d i f f i c u l t to accept a c a p i t a l commitment of an order of magnitude of three to four b i l l i o n 1981 Can.Dol. when i t i s known that the i n i t i a l estimate may e a s i l y be wrong by a b i l l i o n d o l l a r s . By the same token, i t i s d i f f i c u l t for the B.C. government to commit 7,888,000 MMCF 48 of natural gas over 20 years without having a reasonable idea of the opportunity cost of t h i s gas. On the other hand, the cost of a non-commitment must also be considered. Using the graph above and the following table where the quantities involved are calculated i t i s possible to estimate how much of the value of the natural gas ( i n 1981 Can.Dol) i s l o s t by operating a smaller plant. An example w i l l i l l u s t r a t e how to make t h i s estimation. ) - 28 -Table 5 Present Value of Quantities Produced Plant Size (MMCF/D) Present Value of Quantity (MCF) 250 218,375,563 500 436,750,500 750 v 655,126,688 1000 873,503,063 Example: i f we operate two 250 MMCFD plants instead of one 500 MMCFD plant, the value l o s t w i l l be ($4.008-$3.751) * 436,750,500,(1981 Can.Dol.) 1. e. value of the natural gas with a 500 MMCFD plant, minus value with a 250 MMCFD plant (smaller because of the economies of scale) times the present value of the quantity of natural gas involved. 2. S e n s i t i v i t y Analysis the sources of v a r i a t i o n i n the estimates P and P p s can be grouped into three categories; (1), the C.I.F. price i n Japan could be d i f f e r e n t than the one used i n the base case; (2) , the actual costs can d i f f e r from the estimated costs; and (3), some assumptions for values used i n the model (e.g. i n f l a t i o n rate) can turn out to be wrong. The analysis of the e f f e c t on P and P of each of these sources of p s va r i a t i o n constitutes an analysis of the s e n s i t i v i t y of these estimates which helps determine how valuable i s a strategy of non-commitment. That i s , i t w i l l h i g h l i g h t how much we do not know about P and P . a) C.I.F. Price i n Japan The i n i t i a l C.I.F. pr i c e and i t s annual rate of i n -crease are two sources of v a r i a t i o n i n the estimated private and.social values. In the base case, the i n i t i a l C.I.F. p r i c i s $7.38 (1981 Can.Dol. /MCF) and i t s annual rate of increase i s equal to the general rate of i n f l a t i o n - - 10%. This represents our guess of what i s going to happen; we do not intend to q u a l i f y t h i s forecast here - but simply to measure how a given deviation from t h i s forecast w i l l a f f e c t the estimated values of the gas. We f i r s t look at the impact of a d i f f e r e n t i t i t i a l C.I.F. p r i c e . Table 6, which follows, shows the estimated values for d i f f e r e n t i n i t i a l p r i c e s . Table 6 Eff e c t of Changed C.I.F. Price on the Estimated Private and Social Opportunity Costs Estimated Social Value (1981CanDol/MCF) Plant Size 1 C.I.F. Price (1981Can.Dol./MCF) (MMCFD) 7.00 . 7 . 36 7.38 7.40 7.76 250 3.334 3.628 3 .645 3 .661 3.956 500 3.597 3.892 3.908 3.925 4.219 750 3 . 738 4.033 4.049 4.066 4.361 1000 3.809 4. 104 4.120 4.137 4.432 - 30 -Estimated Private Value (l981Can.Dol./MCF) Plant Size C.I.F. Price (1981Can.Dol./MCF) (MMCFD) 7 .00 7 . 36 7.38 7 .40 7 . 76 250 3.44-0 3 . 735 3 . 751 3 . 768 4.062 500 3.697 3 . 992 4.008 4.024 4.319 750 3 . 832 4. 127 4.144 4.160 4.455 1000 3.901 4.196 4.212 4.228 4 . 523 The r e g u l a r i t y of the figures, which i s to be expected allows us to capture the impact of the i n i t i a l C.I.F. pr i c e i n a ^ simple rule; for each deviation from the base case of $0.01 (1981Can.Dol.) the estimated values w i l l be o f f by about 0.820. This means that i f , for example, B.C. only gets the lowest p r i c e paid currently by Japan for LNG($7.10/MCF) the estimated values of P and P are about 230 too high, p s • ' i . e . the actual P and P are about 7% smaller. P s With a project covering such a long period as 25 years i t i s easy to. imagine how important the rate of increase i n the C.I.F. p r i c e i s . In fact the issue of the annual rate of increase on agreed prices for LNG has been the subject of numerous c o n f l i c t s around the world i n recent years - and the escalation systems i n place vary widely. To measure the impact of t h i s source of v a r i a t i o n , we calculated the . ef f e c t of a r e a l growth i n the C.I.F. pr i c e on values of P and P constant In rea l terms. This way our basis for p s J comparison i s the same as i n a l l other cases. The r e s u l t s are shown below for a 250 MMCF/D plant; - 31 -Table 7 S e n s i t i v i t y of P and P to the assumed r e a l rate of growth p s , of the C.I.F. pr i c e Real Rate of Growth of C.I.F. Price 1.0 1.02 1 .05  P 3.751 5.4-45 8.962 P P 3.645 5.339 9.069 S(l981Can.Dol.) We can see that the impact i s indeed very important but i t must be remembered that t h i s table assumes a constant rea l value f o r B.C.'s gas. In other words, i f we assume that the s o c i a l value of B.C.'s gas should grow at 2% re a l per annum (because of increased s c a r c i t y or whatever), then the figures "3.751" and "3.645" for P and P w i l l be assoc-a p s iated with a 2% annual increase i n the r e a l C.I.F. price of LNG ("1.02" i n the above table) and the other figures w i l l be d i f f e r e n t . Since the measurement of the impact of the rate of growth of the C.I.F. pr i c e involves d i r e c t l y the ques-t i o n of the rate of growth of the value of B.C.'s gas i n alternate uses - an issue beyond the scope of t h i s paper -i t i s not discussed further. However, the above ca l c u l a t i o n s i l l u s t r a t e the magnitude of growth i n the opportunity cost of B.C. natural gas. i - 32 -b) Vari a t i o n of the Cost Estimates i) Capital Costs It was mentioned before that the c a p i t a l costs are a large unknown i n the study of the d e s i r a b i l i t y of an LNG plant i n B.C. This section examines how and P g vary with v a r i a t i o n s i n the c a p i t a l costs. Table 8, below, shows the res u l t s of d i f f e r e n t simulations using multiples of the estimated c a p i t a l costs of the base case. Table 8 S e n s i t i v i t y of Private and Social Opportunity Costs to Changes i n Assumed Capital Costs Estimated Social Value (1981- Can. Pol. /MCF) Plant Size (MMCFD) Multiples of the Estimated Capital Costs 0.5 0.8 1.0 1.2 2.0 250 4.590 4.023 3.645 3 .267 1.755 500 4.737 4.240 ; 3.908 3.577 2.251 750 4.814 4.355 4.049 3.744 2. 520 1000 4.853 4.413 4.120 3.827 . 2.656 Estimated Private Value (1981 Can.Dol./MCF) Plant Size Multiples of the Estimated Capital Costs (MMCFD) 0.5 0 . 8 1.0 1.2 2.0 250 4.643 4.108 3.751 3 . 394 1.967 500 4.787 4.319 4.008 3.696 2.450 750 . 4.681 4.431 4.144 3.857 2.709 -1000 4. 899 4.487 4.212 3 .937 2.839 - 33 -In dealing with the c a p i t a l costs, we lose the r e g u l a r i t y that allowed the d e f i n i t i o n of a simple rule i n the case of the C.I.F. price because of economies of scale and taxation factors. Some element of r e g u l a r i t y remains however. For a given plant size, the impact of a v a r i a t i o n i n the c a p i t a l cost i s a constant proportion but d i f f e r e n t between the s o c i a l and private values. We can summarize the impact i n a table 9. This table shows the v a r i a t i o n of the estimated value, i n 1981 Can.Dol./MCF, associated with a deviation from the estimated cost of 1% (the impact w i l l be i n the opposite d i r e c t i o n from the deviation). Table 9 E f f e c t of a Variation of 1% i n the Assumed Capital Cost on P and P p s m 4- o • , n l „ V a r i a t i o n From _ Plant Size (MMCF/D) P P p s 250 0.0178 (.5%) 0.01.89 (.5%) 500 0.0156 (.4%) 0.0166 (.4%) v 750 0.0143 (.35%) 0.0153 (.37%) 1000 0.0137 (.32%) 0.01466 (.35%) We can see that the impact of a given v a r i a t i o n i n the assumed c a p i t a l costs i s smaller the larger the plant and i s smaller for the Pp because part of the t o t a l impact i s passed on to the government through taxes. Despite the non-uniformity of the impact, we can summerize i t roughly i n t h i s way: - 34 -each 10% of deviation between the actual and estimated c a p i t a l costs w i l l r e s u l t i n a deviation from P and P of p , s about 15.50/MCF (or about 4%). This value of 15.50 i s only a rough index of the order of magnitude involved and the reader should refer to the table above for more precise mea-sures of the impact of variations i n the c a p i t a l costs. i i ) Operating costs Table 10, below, shows the estimated private and s o c i a l values for d i f f e r e n t multiples of the base case l e v e l of operating costs. Table 10 S e n s i t i v i t y of the Private and Social Opportunity Costs to Changes i n Assumed Operating Costs Estimated Social Value Plant Size Multiples of the Estimated Operating Costs (MMCF/D) 0 . 5 1_J0_ 2.0 250 3.899 3.645 3.136 500 4.147 3.908 3.430 750 4.282 4.049 3.584 1000 4.350 4.120 3.661 - 35 -Estimated Private Value (1981Can.Dol./MCF) Plant Size Multiples of the Estimated Operating Costs (MMCFD) 0^5 1^0 2.0 250 4.006 3.751 3.242 500 4.247 4.008 3.530 750 4.376 4.144 3.678 1000 4.442 4.212 3.753 Economies of scale are present i n the operating costs so that again the impact varies with the si z e of the plant. There i s no wedge created by the tax structure, i . e . no CCA equivalent for the operating costs, hence the impact Of a v a r i a t i o n i n the operating costs i s the same on the private and s o c i a l values. The table below (11) measures t h i s impact, for the d i f f e r e n t plant sizes i n 1981 Can.Dol./MCF va r i a t i o n s associated with a v a r i a t i o n of 1% of the operating costs from the base case estimate (again i n opposite d i r e c t i o n s ) . Table 11 Ef f e c t of a Variation of 1% i n the Assumed Operating Costs on P and P p s Plant Size (MMCF/D) Va r i a t i o n 250 0.00509(.13%) 500 0.00478(.12%) 750 0.00465(.11%) 1000 0.00459(.10%) To get an idea of the order of magnitude involved, we can - 36 -refer to the simple rule that follows: for each deviation of the operating costs of 10% from the base case estimate, the private and s o c i a l values w i l l vary by about 4.80/MCF (or about 1.2%) i n the opposity d i r e c t i o n . c) Va r i a t i o n i n the Assumed Values of the Parameters The heading of t h i s section well represents the type xof sources of v a r i a t i o n involved here. We can have the correct estimate for the C.I.F. price and the costs and s t i l l f i n d our estimated values d i f f e r i n g from the actual values because some assumptions of values turn out to be wrong. A model i s a s i m p l i f i e d representation of r e a l i t y ; i t i s possible that our model represents a scenario d i f f e r e n t from what would act u a l l y happen; we w i l l measure here the impact of t h i s source of v a r i a t i o n . There are four assumptions that need to be analysed here: the rate of i n f l a t i o n , the debt-equity r a t i o , the CCA, and the investment schedule. The table below shows the r e s u l t s with d i f f e r e n t general rates of i n f l a t i o n (plant size equals 500 MMCF/D). Table 12 S e n s i t i v i t y of P and P to the Assumed Rate of I n f l a t i o n J p s Rate of I n f l a t i o n (% per annum) 8% 10% 12% 14% 4.045 4.008 3.971 3.933 3.924 3.908 3.891 3.872 (1981 Can.Dol./MCF) - 37 -The impact d i f f e r s between the private and s o c i a l values because of taxation (CCA) but i s uniform for both. We can expect the impact to vary with the size of the plant but we s i l l can summarise i t i n a simple rule for easy reference; for each 1% of v a r i a t i o n i n the rate of i n f l a t i o n from the base case 10%, the estimated private value w i l l vary by about 20/MCF and the estimated s o c i a l value w i l l vary by about .80/MCF, both i n the opposite d i r e c t i o n . The corporate organization of the project can also be d i f f e r e n t from that modelled. Two such sources of difference are: the debt-equity r a t i o and the CCA. The impact of t h i s source of v a r i a t i o n i s l i m i t e d to the private value of the natural gas since the corporate organization simply determines the sharing of s o c i a l costs between the firm and the govern-ment and not the .magnitude of these s o c i a l costs; the sharing of costs i s i n fact done through taxation. The impact of the CCA i s measured below. Table 13 S e n s i t i v i t y of P and P to the Assumed CCA P s Scale 500 MMCF/D Multiples yof the 'Estimated CCA 0.8 1.0 1.2 P 3.881 4.008 4.135 P P 3.908 3.908 3.908 s The private value becomes smaller than the s o c i a l value when the actual tax payments become larger than they are on - 38 -average for a c a p i t a l investment of t h i s s i z e . The impact of variations i n the CCA i s uniform for a given plant si z e and i s equal to about 6.50/MCF for each 10% of v a r i a t i o n i n the CCA. A 10% v a r i a t i o n i n the present value of the CCA can be brought about by a number of changes i n the c l a s s i f i c a -t i o n of the t o t a l investment where a slower allowed deprecia-ti o n w i l l mean a lower CCA. For instance, i f storage tanks for LNG were allowed a CCA of 5% as opposed to the 10% allowed for a "conventional" storage tank (water or f u e l ) , the present value of the CCA would decrease. Such a s i t u a t i o n could arise because there are no base-load LNG plants i n Canada. The c l a s s i f i c a t i o n decision has yet to be formally made by the government o f f i c i a l s . The debt-equity r a t i o has been set at 60/40 for the base case. But, we could f i n d that the type of firms interested i n t h i s type of project are much less r i s k y than anticipated because of t h e i r d i v e r s i f i c a t i o n . A higher debt-equity r a t i o of 75/25 was tested and the re s u l t s are shown below. Table 14 S e n s i t i v i t y of P and P to the Assumed Debt/Equity Ratio 250 500 750 1000 p p 3.938 4.171 4.294 4.356 p s 3.645 3.908 4.049 4.12 P (60/40) 3.751 4.008 4.144 4.212 The impact of a d i f f e r e n t debt-equity r a t i o can be estimated roughly at .60/MCF for each 1% increase i n the proportion - 39 -of debt, which means that i t would take a decrease of about 15% (from the base case) i n the proportion of debt to make the private value roughly equal to the s o c i a l value. IV CONCLUSION The s o c i a l value of B.C.'s natural gas used as LNG for exports to Japan was estimated at between $3,645 and $4.12 1981 Can.Dol./MCF, depending on the plant s i z e . To put t h i s estimate i n perspective, we can compare i t to the s i m i l a r value for the gas exported by pipeline to the U.S. The border price of t h i s gas i s $5.38/MCF and the t o t a l cost of the pipeline transportation i s about $0.70/MCF^ which leaves a value of about $4.68 1981 Can.Dol./MCF at the input-end of the p i p e l i n e . But t h i s value of $4.68/MCF i s not necessarily a guide to the future s o c i a l value of.B.C.'s natural gas. For .one thing, we need to know i f we can s e l l more to the U.S. than we are s e l l i n g now and at what price, secondly, the values of $3,645 to $4.12/MCF are simply point estimates and not the s o c i a l values of B.C.'s gas used as LNG. Being interested i n the s o c i a l value of B / c ' s gas used as LNG, we expanded these point estimates through a s e n s i t i v i t y analy-s i s where we measured the impact of d i f f e r e n t sources of v a r i a t i o n . The importance of the s e n s i t i v i t y analysis can be i l l u s t r a t e d with the following example r e l a t i n g to the figures above: i f the C.I.F. price of LNG turns out to be 500/MCF higher than i n the base case i . e . , $7.88 or 210 lower i than the highest p r i c e paid by Japan for LNG, and the actual c a p i t a l costs turn out to be 10% less than estimated, - 40 -the netback of a 1000 MMCF/D LNG plant would-be about $4,675 1981 Can.Dol./MCF or about the same as the netback from exports to the U.S. To t a l k seriously about the s o c i a l value of B.C.'s gas used as LNG we must include an i d e n t i f i c a t i o n of the d i f f e r e n t sources of v a r i a t i o n of the point estimate and a measure of the impact of these sources of v a r i a t i o n . The s e n s i t i v i t y analysis revealed that the C.I.F. price and the c a p i t a l costs are, as should have been expected, the most important sources of v a r i a t i o n i n terms of impact. This study stopped at the measurement of these impact. The next step would be to analyse i n d i v i d u a l l y each of these sources of v a r i a t i o n , with more emphasis on those with the more s i g n i f i c a n t impacts, and come up with some sort of p r o b a b i l i t y d i s t r i b u t i o n of possible states. We must not be fooled by the fact that the estimated private and s o c i a l values are very close and l e t the firms make the decision as to whether or not to go ahead assuming .. that because of the s i m i l a r i t y of these values,, what w i l l be good for the firm w i l l be good for society. We must remember the decision rule of the firm: the firm w i l l go ahead only i f the private opportunity cost of the natural gas used as LNG i s greater than the private opportunity cost i n any other use and greater than the private cost of supplying natural gas. The fa c t that the private opportunity cost i n use as LNG i s close to the s o c i a l opportunity cost i n t h i s use does not say anything about the r e l a t i o n between - Al -the opportunity cost i n other uses and the s o c i a l opportunity cost i n these uses. We can tr u s t the private firm to make the best decision i n terms of s o c i a l welfare only i f the tax system does not a l t e r the ranking of the d i f f e r e n t opportunity costs i n use and i f the private cost of supplying natural gas i s made equal to the s o c i a l cost. These conditions go far beyond a s i m i l a r i t y between the private and s o c i a l oppor-tunity cost i n use ,as LNG. - 42 -Footnotes 1. M.W.H. Peables (1980), p.7 2. S McCune (1981), p.1 3. J. Segal (19.80), p.515 4. loc. c i t . 5. A p r i l 22nd, 1981, Section C, page 1 6. Carter O i l and Gas Limited (1979) 7. The Province, A p r i l 22nd, 1981, Section C, page 1 8. J. Segal (1980), pp. 515-516 9. Between Prince George and Prince Rupert a new pipeline w i l l d e f i n i t e l y be required as the a v a i l a b i l i t y on the e x i s t i n g Northern Gas P i p e l i n e i s l i m i t e d to an additional 40 MMCF/D. Between Fort St. John and Prince George, a new p i p e l i n e would not be necessary i f natural gas destined for the LNG plant displaces natural gas destined to the U.S.; but our statement about the need for a new pipeline over the entire distance between Fort ST. John and Prince Rupert remains v a l i d i f we equate the opportunity cost of the p i p e l i n e capacity taken away from the U.S. exports to the cost of a new p i p e l i n e - which can not be completely wrong. 10. A l l cost figures are transformed into 1981 Can.Dol. by using a 10% a year i n f l a t i o n rate and a 1.2 Can.Dol/U.S. Dol. exchange rate.. 10% i s used becasue we judged that no e x i s t i n g index could predict well the cost escalation of an LNG project i n B.C. In t h i s context, the cost escalation was set equal to the general rate of i n f l a t i o n . 11. Carter O i l and Gas Limited (1979) 12. Ibid 13 O f f i c e of Technology Assessment, Congress of The United States 14 To f i n d the value of natural gas we w i l l use t h i s type of formula: PV(revenues)-PV(all costs except natural gas) Value of PV(quantity of natural gas purchased) ~ nat. gas - 43 -15. National Energy Board (1977) 16. Carter O i l and Gas Limited (1979) 17. Ibid 18. P.J. Anderson and E.J. Daniels (1977) 19. See for example, Alt e r n a t i v e Energy Futures p.81 20. Carter O i l and Gas Limited (1979) 21. Ibid 22. J.G. Seay, P.J. Anderson, E.J. Daniels (1978) p. 15 23. Ibid, p.16 24. For example, A.H. Schwendtner (1977) p.54 25. It takes 28.4 days for a round t r i p of 10,150 na u t i c a l miles between Arzew (Algeria) and La Salle (U.S.A.). (Alternative Energy Futures, p. 83). The return distance between Prince Rupert and Tokyo i s about 8800 naut i c a l miles. A ship operates about 330 days per year. 26. Vedeler (1981) p.88 or J. Segal (1980) p. 376. Some LNG must be kept i n the tanks of the ships at a l l times to keep those tanks cold, so the 5% applies to the return t r i p . 27. Office of Technology Assessment, Congress of the U.S., p.85 28. BTU p a r i t y assumes that o i l and gas are valued according to t h e i r BTU content. This i s the opposite of what we observe i n r e a l i t y . The crude o i l buyer i s usually interested i n light-end y i e l d s (which have low BTU content) while the gas buyer i s interested i n the BTU content. This s i t u a t i o n arises from the fact that o i l and gas are e s s e n t i a l l y used for d i f f e r e n t purposes. '29. M.W.H. Peables (1980) p.7 30. J. Segal and F.E. Niering (1980) p.373 31. Ibid, p.377 32. Abu Dhabi, Brunei, Indonesia and U.S.A. 33. Chile, Malaysia, A u s t r a l i a , Sumatra and Kalimatan 34. J. Segal and F.E. Niering (1980) p.375 - 44 -35. J., Segal (1980) p.514 36. loc. c i t . 37. loc. c i t . 38. The v a r i a b i l i t y of the prices i s misleading because i n fact only Brunei and Indonesia represent major projects and we can be f a i r l y sure that the Japanese are paying, i n these instances, what they are r e a l l y ready to pay for LNG. (The project with the U.S.A. expires i n 1984 while the one with Abu Dhabi has been caught i n the "BTU p a r i t y " dispute). 39. W.J. Baumol (1968) p.788 40. Ibid p.788 41. E.J. Mishan (1973) 42. loc. c i t . 43. There i s assumed to be only one general rate of i n f l a t i o n — 10%. 44. Based on the flow presented i n Carter's projections. Carter O i l and Gas Ltd. P r e f e a s i b i l i t y Study. 45. Most of the information i n t h i s section comes from Price Waterhouse (1976) 46. From Commerce Clearing House Canadian Limited (1980) 47. J.F. H e l l i w e l l , Impact of a Mackenzie Pipe l i n e on the National Economy. 48. The amount of natural gas necessary to feed a 1000 MMCF/D plant. 49. From Ministry of Energy Mines and Petroleum Resources, B r i t i s h Columbia (1980) - 45 -BIBLIOGRAPHY ANDERSON, P.J. and DANIELS, E.J., Economic Considerations and  Operating History of Base-Load LNG Projects, I n s t i t u t e of Gas Technology, Chicago, 1977 BAUMOL, William J., "On the Social Rate of Discount", American  Economic Review, September 1968, Vol. LVIII, No.4, p.788 Carter O i l and Gas Limited, P r e f e a s i b i l i t y Study,Main Report, Prepared by Acres Consulting Services Limited and Acres Davy Mckee Limited, December 1979, unpublished Commerce Clearing House Canadian Limited, Canadian Depreciation  Guide, 15th Edition, 1980 HELLIWELL, John F., "Impact of a Mackenzie Pipe l i n e on the National Economy" i n P.H. Pearse ed. The Mackenzie Pipe-l i n e : A r t i e Gas and Canadian Energy Policy , Toronto, pp. 143, 182 McCUNE, Shane, "Gas-for-Japan Race Heating Up", The Province, Section C, p. 1, Wednesday A p r i l 22nd, 1981 Ministry of Energy Mines and Petroleum Resources, B r i t i s h Columbia, A P r i c i n g P o l i c y For Indu s t r i a l and Processing  Application of B.C. Natural Gas, 1980 MISHAN, E.J., Economics for Social Decisions, Praeger Publishers, N.Y., 1973 National Energy Board, Reasons for Decision i n the Matter of an Application Under Part IV of.the National Energy Board  Act of ICG Transmission Limited, January, 1977 Off i c e of Technology Assessment, Congress of the United States, Al t e r n a t i v e Energy Futures, Part I, The Future of Liquefied  Natural Gas Imports, Washington PEABLES, Malcolm W.H.,"World LNG Trade: Past Achievements, Current Status, and Future Prospects", Chemical Economy  and Engineering Review, A p r i l 1980, p.7 Price Waterhouse, Doing Business i n Canada, Information Guide, March, 1976 SCHWENDTNER, A.H."LNG Transportation Costs", Pip e l i n e and  Gas.Journal, August, 1977, p. 52 Vol.204, No. 32 SEAY, J.Glenn, ANDERSON, P.J. and DANIELS, E.J., The LNG  Industry: An Overview of Projects and Costs, ASME Annual Conference, Houston, I n s t i t u t e of Gas Technology, 1978 - 46 -SEGAL, Jeffrey, "Slower Growth for the 1980's-World Survey, LNG Market", Petroleum Economist, December, 1980, p. 513, Vol. XLVII, No. 12 SEGAL, Jeffrey, and NIERING, Frank E. J r . , "Special Report on World Natural Gas P r i c i n g " , Petroleum Economist, September, 1980, p. 373, Vol.XLVII, No. 9 VEDELER, Alex, "Guidelines Can Aid i n Chartering LNG Vessels", O i l and Gas Journal, January 12, 1981, Vol. 79, No. 2, p.88 UHL, A.E. and GIESE, J.M., "LNG Export-Import System Economics", Pipeline and Gas Journal, June 1973, p.41, Vol.200, No. 7 - 47 -APPENDIX 1 Overall Check of the Cost Estimates The cost estimates come from many d i f f e r e n t sources and one can not be sure that estimates are on a comparable basis. This could make one suspicious of the v a l i d i t y of the o v e r a l l picture created. To eliminate these doubts an "overall check" on the cost estimates was c a r r i e d out. An "overall check" i s a comparison between the t o t a l cost per MCF implied by our cost estimates and various figures f o r t o t a l cost taken from the l i t e r a t u r e ^ - cost per MCF i s a standard way of presenting costs i n the trade l i t e r a t u r e . In.the table below, I present my t o t a l cost estimate per MCF, as implied by the cost estimates of section B-2, and the reference figures ( a l l i n 1981 Can.Dol.): • • - ' Reference 0.2572 to 0.5145 2 1.452 to 1.848 3 Estimate Pipeline 0.638 to 0.87 L i q u i f i c a t i o n 1.307 to 1.733 Shipping 1.522 1. These figures can only be used for such rough comparison purposes because the way they are obtained i s usually not mentioned e.g. Implied discount rate, depreciation rate i s not known. 2. Uhl, A.E., and J.M."Giese, p.42 3.. Special Report, Segal, p.377 4. Special Report, p.376. The estimate used i s the current cost adjusted for i n f l a t i o n because I do not believe that the new ships w i l l be much more expensive given the pre v a i l i n g market conditions. - 48 -My cost figures for the pipeline are s i g n i f i c a n t l y higher than the reference figures but I can f e e l comfortable with that; as I mentioned i n discussing p i p e l i n e costs, c a p i t a l costs are overwhelmingly important here and i t should be expected that the c a p i t a l costs for the B.C. LNG project's p i p e l i n e w i l l be higher than "normal" because of the ruggedness of the t e r r a i n . In fact, i f I adjust the reference range to account for the ruggedness of the t e r r a i n , I get a reference range of $6.47 to $0.9404 (1981 Can.Dol./MCF) which covers e n t i r e l y my estim-ates. Furthermore, the economies of scale factor i s s i m i l a r to that of the reference - about 240/MCF between 290 and 1160 MMCF/D. My l i q u e f a c t i o n cost estimates are uniformly low by about 10%; but, my base case estimates should be taken with an accuracy of plus or minus 20% - because the basic information i s quoted t h i s way - so t h i s r e s u l t i s acceptable. The shipping estimate i s about 15% lower. But, the market for LNG tankers i s very sof t and there i s no market price but only i n d i v i d u a l l y negotiated prices that account for heavy Import-Export Banks support. In fact, 15% on #225MM (1981 Can. Dol.) i s about $34MM(1981 Can.Dol.) and one of our sources 5 a c t u a l l y quotes a range of over $40MM (1981 Can.Dol.) i n the price of LNG tankers. These o v e r a l l checks thus should s a t i s f y the reader that the preferred estimates, composing the input i n the base case, create a reasonable picture of the actual costs to be expected i f t h i s kind of project goes ahead. 5. J.G. Seay, P.J. Anderson, and C.J. Daniels (1978) - 49 -APPENDIX 2 Elaboration of the equation determining the private value. We s t a r t with: PV(REVENUES)-PV(COSTS)=0 or, PV(REVENUES)-PV(CAP.COSTS)-PV(OP.COSTS)-PV(NAT.GAS)-PV(TAXES)=0 where, PV(TAXES)=.49*PV(REVENUES-OP.COSTS-DEBT COSTS-CCA-NAT.GAS) so that, .51*PV(NAT.GAS)+.49*PV(DEBT C0STS)+.49* PV(CCA)=0 or, .51*PV(REVENUES)-PV(CAP.COSTS)-.51 *PV(OP.COSTS)+.49*PV (DEBT C0STS)+.49*PV(CCA)=.51*PV(NAT.GAS). To further modify t h i s l a s t equation we need to better define our objective; we are looking for a price P^ defined i n 1981 Can.Dol. which, while increasing at a given % per annum, w i l l produce the flow of annual disbursements by the firm f o r natural gas purchases that" w i l l s a t i s f y the equation above. . We w i l l c a l l the left-hand side of the above equation L, L=.51*PV(REVENUES)-PV(CAP.COSTS)-.51*PV(OP.COSTS) + ,49 *PV(DEBT COSTS)+.49*PV(CCA). We thus have L=.51*PV(NAT.GAS) or, L=.51*PV(Q * P * s ) , where Q i s the quantity of natural gas P P P purchased annually and "s" i s . a seri e s element that transforms P into the current price of natural gas. p We are looking for P^; L=.51*Q *P *PV(s) - 50 -where PV(s) = (1+STP) 2 0 * (1+P.I.) 5 - (1+P.I.) 2 5 and (1+STP) 2 5 - (1+STP) 2 4 * (1+P.I.) STP = re a l rate of s o c i a l time preference P.I.(price i n f l a t o r ) = rate of i n f l a t i o n of the price of nat.gas general rate of i n f l a t i o n (10%) In the actual computer model, the units are m i l l i o n s of d o l l a r s (MM$) and m i l l i o n s of cubic feet so that the P calculated i s P expressed i n I981MM$ per MMCF , hence m u l t i p l i e d by 1000 to get a figure i n 1981 Canadian d o l l a r s per MCF. The equation of l i n e s 274-279 i n the computer model thus produces a price that can be e a s i l y compared with s i m i l a r prices for other uses because i t i s expressed i n standard units ($/MCF) and furthermore, i t i s expressed i n 1981$. 1. In the base case P.I. i s equal to,one. -51-APPENDIX 3 The computer model I d e n t i f i c a t i o n of the Parameters A(l) Capacity i n MMCFD A(40) Quantity of natural gas,in MCF,necessary to produce one MCF of LNG A(41) Percentage of the amont of n a t u r a l gas bought that i s used as feedstock A(42) Percentage of the amount of n a t u r a l gas bought that i s used as f u e l f o r the l i q u e f a c t i o n plant A(43) Percentage of the amount of n a t u r a l gas bought that i s used as f u e l f o r the ships A(44) S o c i a l value of B.C.'s na t u r a l gas A(50) P r i c e of the natural gas used as feestock($/MCF) A(51) P r i c e of the natural gas used as f u e l ($/MCF) A(52) C.i.F. p r i c e i n Japan ($/MCF) ' A(59) P r i c e i n f l a t o r for the C.i.F. p r i c e i n Japan A(66) Adjustment factor f o r the t o t a l c a p i t a l cost of the p i p e l i n e (for s e n s i t i v i t y analysis) A(67) Adjustment factor f o r the t o t a l c a p i t a l cost of the l i q u e f a c t i o n plant ( f or s e n s i t i v i t y analysis) A(68) Adjustment factor f o r the t o t a l c a p i t a l cost of the ships (for s e n s i t i v i t y analysis) A(85) (1-CCA) f o r pipe l i n e s A(86) (1-CCA) f o r ships A(87) (1-CCA) f o r storage tanks A(88) (1-CCA) f o r buildings A(94) 1 plus the r e a l r a t e of s o c i a l time preference A(100) Number of days of production per year 3 A(101) C a p i t a l cost of a 125,000 m LNG tanker ( i n MM '81C$) -52-A(102) A(103) A(104) A(105) A(106) A(107) A(108) A(109) A(110) A(117) A(121) A(122) A(123) A(124) A(125) A(126) A(127) A(132) Ca p i t a l cost of one mile of p i p e l i n e per MMCFD of c a p a c i t y , i f capacity i s smaller than 290 MMCFD ( i n MM'81C$) Cap i t a l cost of one mile of p i p e l i n e per MMCFD for that p o r t i o n of the capacity ( i n MMCFD) that i s greater than 290 and smaller than 580 ( i n MM *81C$) Capit a l cost of one mile of p i p e l i n e per MMCFD for that portion of the capacity ( i n MMCFD) that i s greater than 580 ( i n MM '81C$) Proportion of the t o t a l investment i n the l i q u e f a c t i o n plant spent i n 1982 Proportion of the t o t a l investment i n the l i q u e f a c t i o n plant spent i n 1983 Proportion of the t o t a l investment i n the l i q u e f a c t i o n plant spent i n 1984 Proportion of the t o t a l investment i n the l i q u e f a c t i o n plant spent i n 1985 Proportion of the t o t a l investment i n the p i p e l i n e spent i n 1983 Proportion of the t o t a l investment i n the p i p e l i n e spent i n 1984 (1-CCA) for machinery (equipment) Proportion of the t o t a l investment i n the p i p e l i n e spent i n 1985 Proportion of the t o t a l investment i n the ships spent i n 1983 Proportion of the t o t a l investment i n the ships spent i n 1984 Proportion of the t o t a l investment i n the ships spent i n 1985 Percentage of the t o t a l c a p i t a l cost of the l i q u e f a c t i o n plant that goes for storage tanks Percentage of the t o t a l c a p i t a l cost of the l i q u e f a c t i o n plant that goes for buil d i n g s Percentage of the t o t a l c a p i t a l cost of the l i q u e f a c t i o n plant that goes f o r machinery (equipment) Proportion of the t o t a l c a p i t a l i n the form of debt -53-A(168) Percentage of the production that i s sold (the remaining part boils off during the-trip) A(169) Price inflator for the natural gas used as feedstock or fuel A(173) 1 plus the general rate of inflation -54-LISTING 1 SUBROUTINE: S O L U I 2 C 3 N C LNG MODEL 4 CDMMON/KEEP/LABX (2*800) y L A B E ( 2 •> 600 ) , DATE ( 1.0 0) yBUM(30)»TEST(800), 5 1 TITLE(20)»Z(800),TEMP(800),A(3000)»X(7»800 ).E(7,600) 6 COMMON/SAVE/K ?K1»K7»M,NED yNEX tNT »NL »NC »NDRR EG« 7 1NDRSHK9M7 »M8 yMAX »NCONTR-NCONV yNSKIP y NPOLyNY EAR s> NREVA ? NRDATA y 8 2C0Nv6»N2»ID»NUr1SX»NUMSE 9 C0MM0N/LLL./Ll»L2rL3»L4»L5»L6»L7 10 COMMON ARG ( 200 ) y F'HI A ( 200 ) y PHIQH ( 25 ) y AREA ( 20 0) 11 LOGICAL DUM 12 INTEGER TITLE y DATE 13 DIMENSION LO(7)yY(800)yYP(800) 14 EQUIVALENCE < Y y Z ) y < L.0 y L1 » L ) 15 NTIME=ID-1901+K7 16 MD=IFIX(A(105)) 17 NTIMD=NTIME-MD 18 NSTAR1=IFIX<A<162)) 19 LIFE=IFIX<A(159)) 20 NYEAR = NSTAR1--81 + LIFE 21 ,' RTIME = NTIME 22 RSTAR1=NSTAR1 23 RLIFE=LIFE 24 IF<NTIME.EQ.81) STPNC)M = A ( 94 ) *A (-173 ) 25 IF<NTIME.EQ.82) STPN0M=A(94)*A(173) 26 ' IF<NT IME.EQ.83) STPNGM=A(94)*A(173) 27. IF<NTIME.GT.83) STPNOM=A<94)*A(173) 28 A(174)=A<ll)*E<Kyl2) + <:l.-A(ll))*E(K»13) 29 ,A(176)=(1/(RLIFE-(RTIME-RSTAR1))) 30 IF(NTIME.EQ.NSTAR1-5) Y(99)=l 31 IF(NTIME.EQ.NSTAR:L-4) Y<99>=A<94>*A<173> 32 IF ( NTIME . GT . NSTAR1-4 ) Y < 99 >=X C Ll'» 99 > *A < 94 ) * A(173) 33 C SCALE 34 Y<1)=A<1) 35 C QUANTITY PRODUCED 36 Y<2)=A(100)*ZC1) 37 C QUANTITY SOLD i 38 Y(3)=E(K»1)*Z(2)*A(168) \ 39 C Q. PROD. CUMULATIVE 40 IFCNTIME.LT.NSTARl) Y(4)=0 4.1 IF(NTIME.EQ.NSTAR1. ) Y(4)=Z(3) 42 IFr ( NTIME . GT • NSTAR1 ) Y ( 4 ) =X < LI » 4 > *STPNOM + Z ( 3 -55-C P R E S E N T V A L U E O F T H E C U M U L A T I V E P R O D . I F ( K 7 . E Q . N Y E A R ) Y ( A ) = Z ( 4 ) / Z ( 9 9 ) C P R I C E O F L N G A ( 3 ) = A ( 5 2 ) / 1 0 0 0 I F < N T I M E . E Q . N S T A R 1 - 5 > Y ( 5 ) = A ( 3 ) I F ( N T I M E . G T . N S T A R 1 - 5 ) Y < 5 > = X < L I i 5 > * A < 1 7 3 > * A ( 5 9 ) C A N N U A L G R O S S I N C O M E Y < 6 ) = E ( K » 1 ) * Z ( 3 ) * Z < 5 > C P R E S E N T V A L U E O F R E V E N U E S Y ( 8 ) = X ( L 1 » 8 > * S T P N D M + Z < 7 ) I F ( K ' 7 . E Q . N Y E A R ) Y ( 8 ) =Z ( 8 ) / Z ( 9 9 ) C P R E S E N T V A L U E O F R E V . P E R M C F I F ( N T I M E . L T . N S T A R 1 ) Y ( 9 > = 0 I F ( N T I M E . G E . N S T A R 1 ) Y < 9 ) = < Z ( 8 ) / Z ( 4") ) # 1 0 0 0 C C A P . C O S T P I P E L I N E Y < 1 2 ) = 1 . 1 6 * Z ( 1 ) I F ( Y ( 1 2 ) . L T . 2 9 0 . 0 ) Y < 1 3 ) = 5 0 0 * < Z < 1 2 > * A ( 1 0 2 > > I F ( Y ( 1 2 ) . G E . 2 9 0 . 0 . A N D . Y ( 1 2 ) . L . T . 5 8 0 . 0 0 ) Y ( 1 3 ) = 5 0 0 * < . 8 4 7 0 0 0 + C ( Z ( 1 2 ) 1 - 2 9 0 . 0 ) * A ( 1 0 3 ) ) ) I F ( Y ( 1 2 ) . G E . 5 8 0 . 0 ) Y ( 1 3 ) = 5 0 0 * ( 1 • 4 0 3 6 0 0 0 + ( ( Z ( 1 2 ) - 5 8 0 , 0 ) * A ( 1 0 4 ) ) ) Y ( 1 4 ) = Z ( 1 3 ) * A ( 6 6 ) C C A P . C O S T L I Q U E . P L A N T I F ( Y ( 1 > . L T . 2 5 0 . 0 ) Y ( 1 5 ) = 1 . 7 6 8 * Z ( 1 ) I F ( Y < 1 ) . G E . 2 5 0 . 0 . A N D . Y ( 1 ) . L T . 5 0 0 . 0 ) Y ( 1 5 ) = 4 4 2 . + ( ( Z ( 1 ) 1 - 2 5 0 . 0 ) * 0 . 9 9 6 ) I F ( Y < 1 ) . G E . 5 0 0 . 0 ) Y ( 1 5 ) = 6 9 1 . + < ( Z < 1 ) - 5 0 0 • 0 > * 0 . 6 6 2 0 ) ) Y ( 1 6 ) = Z < 1 5 ) * A ( 6 7 ) C C A P C O S T S H I P S Y ( 1 9 ) = ( Z ( 2 ) / 3 6 4 3 0 . 0 ) * A ( 1 0 1 ) Y ( 2 0 ) = Z < 1 9 ) * A < 6 8 ) C T O T C A P C O S T S Y ( 2 1 ) = Z < 1 4 ) + Z ( 1 6 ) + Z ( 2 0 ) C I N V . I N P I P E L I N E I F ( N T I M E • E Q . N S T A R 1 - 5 ) Y ( 2 4 ) = 0 I F ( N T I M E . E Q . N S T A R l - 4 ) Y ( 2 4 ) = 0 I F ( N T I M E . E Q . N S T A R l - 3 ) Y ( 2 4 ) = Z ( 1 4 ) * A ( 1 0 9 ) * A ( 1 7 3 ) * * 3 I F ( N T I M E . E Q . N S T A R l - 2 ) Y ( 2 4 ) = Z ( 1 4 ) * A ( 1 1 0 ) * A ( 1 7 3 ) * * 4 I F ( N T I M E . E Q . N S T A R 1 - 1 ) Y ( 2 4 ) = Z ( 1 4 ) * A ( 1 2 1 ) * A ( 1 7 3 ) * * 5 I F ( N T I M E . E Q . N S T A R l ) Y ( 2 4 ) = 0 I F ( N T I M E . G T . N S T A R 1 ) Y ( 2 4 ) = 0 C I N V . I N L I Q U E . P L A N T I F ( N T I M E . E Q . N S T A R l - S ) Y ( 2 5 ) = 0 I F ( N T I M E . E Q . N S T A R l - 4 ) Y ( 2 5 ) = Z ( 1 6 ) * A ( 1 0 5 ) * A ( 1 7 3 ) * * 2 I F ( N T I M E . E Q . N S T A R 1 - 3 ) Y ( 2 5 ) = Z ( 1 6 ) * A ( 1 0 6 ) * A ( 1 7 3 ) * * 3 -56-87 IF<NTIME.EQ.NSTARl-2) Y < 25 > = Z (16 >'*A < 107 > *A ( 173)**4 88 IFr < NTIME . EQ • NSTAR1-1 ) Y<25>=Z<16>*A<108>*A< .1 73)**5 89 IF<NTIME.EQ.NSTAR1) Y<25>=0 90 IF(NTIME.GT.NSTAR1 ) Y(25>=0 91 C INV. IN SHIPS 92 IF(NTIME.EQ.NSTARl-S) Y(26)=0 93 IFCNTIME.EQ.NSTAR1-4) Y(26)=0 94 IF(NTIME.EQ.NSTAR1-3) Y(26)=Z<20)*A(122)*A( 173)**3 95 IF(NTIME.EQ.NSTAR1-2) Y(26)=Z(20)*A(123)*A( 173>**4 96 IF(NTIME.EQ.NSTARl-l) Y<26)=Z(20)*A(124)#A< 173)**5 97 IF(NTIME.EQ.NSTAR1) Y<26>=0 98 IF(NTIME.GT.NSTARl) Y(26)=0 99 C TOT INV IN CURRENT $ 100 Y ( 2 7 ) = ( Z ( 2 4 ) + Z ( 2 5 ) + Z ( 2 6 ) ) 101 C CUMULATIVE INVESTMENT 102 IFCNTIME.EQ.NSTAR1-5) Y(28)=0 103 IF(NTIME.GT.NSTARl-S) Y(28)=X(L1,28)+Z(27) 104 C PRESENT VALUE OF THE INVESTMENT 105 Y(29)=X<L1»29)*STPN0M+Z<27) 106 IF (K7.EQ. NYEAR) YJ'29 ) =Z ( 29 ) /Z ( 99 ) 107 C ECONOMICALLY UNDEPRECIATED CAPITAL. 108 IF(NTIME.LT.NSTARl) Y(30)=Z(28) 109 IF(NTIME•GE.NSTAR1) Y(30)=X(LIr30)-.05*Z<28 ) 110 C PRESENT VALUE OF DEPRECIATION(ECONOMIC)' 111 YC31)=E(K»1)*.05*Z(28) 112 Y ( 3 2 ) =X ( L 1 F 3 2 ) *S T P N 0M + Z ( 3 1 > 113 IF(K7.EQ.NYEAR) Y(32)=Z(32)/Z(99) 114 C CUMULATIVE INVESTMENT PIPELINE 115 IF(NTIME.EQ.NSTAR1-5) Y(34)=0 116 IF(NTIME.GT.NSTARl-S) Y(34)=X(LI 934)+Z(24) 117 C NON-DEPRECIATED CAPITAL(ECON) PIP. 118 IFCNTIME.LT.NSTAR1) Y(35)=Z(34) 119 IF(NTIME.GE.NSTAR1) Y(35 )=X(LIt35)-.05*Z(34 ) 120 C CUMULATIVE INVESTMENT LIQUE. PLANT 121 IF(NTIME.EQ.NSTAR1-5) Y(36)=0 122 IFCNTIME.GT.NSTAR1-5) Y ( 36 ) =X ( L. 1 , 36 ) +Z (25 ) 123 C NON-DEPRECIATED CAPITAL(ECON) L . P . 124 IF(NTIME,LT.NSTAR1) Y(37)=Z(36) 125 IF(NTIME.GE.NSTARl) Y(37)=X(LIt37)-.05*Z(36 ) I 126 C CUMULATIVE INVESTMENT SHIPS 127 IFCNTIME.EQ.NSTAR1-5) Y(38)=0 128~ IF(NTIME.GT.NSTARl-5) Y ( 3 8 ) = X ( L I * 38)+Z(26) -57-129 C NON-DEPRECIATED CAPITAL(ECON) SHIPS 130 IF(NTIME.LT.NSTAR1) Y(39)=Z(38) 1 3 1 IF(NTI ME.GE.NSTAR1) Y ( 3 9 ) = X ( L 1 r 3 9 ) - . 0 5 * Z ( 3 8 ) 132 C OP. COST LIQUE. 133 IF(Y<1>.LT.250.0) Y'(40)=Z(1>*.06292KE(K?1) 134 IF(Y <1).GE.250.0•AND.Y(1).LT•500•0) Y(40)=l 5.73+((Z(l) 135 1-250.0)*.03872)*E(Kr1) 136 IF(Y(1).GE.500.0) Y(40)=25.410+((Z <1)-500.0 )*.03542)*E(K91) 137 Y(41)=Z(40)*A(60) 138 C OP•COST SHIPPING 139 Y(42)=(Z(2)/36430«0)*12.24*E(K»1) 140 Y(43)=Z(42)*A(61 ) .141 C OP. COST PIPELINE 142 Y(44)=E(K»1)*0.000059976*Z(12)*A(100) 143 Y(45)=Z(44)*A(62) 1 4 4 C OPERATING COSTS ESCALATED(FOR INFLATION) 145 C SHIPPING 146 IFCNTIME.LE.NSTARl) Y(46)=Z(43)*(A(173)**5) 147 IF(NTIME.GT.NSTARl) Y(46)=X(L1,46)*A(173) 148 C LIQUEFACTION PLANT 149 IF(NTIME.LT.NSTAR1) Y(47)=0 150 IF < NTIME.EQ.NSTAR1) Y(47)=Z(41)*(A(173>**5> 151 IF(NTIME.GT.NSTARl) Y(47)=X(LIt47)*A(173) 152 C PIPELINE 153 IF(NTIME.LE.NSTAR1) X<48)=Z(45)*(A(173)**5) 154 IF(NTIME.GT.NSTAR1) Y(48)=X(LI,48)*A(173) 155 C COST OF PIPELINE PER MCF 156 IF(NTIME.LT.NSTARl) Y(49)=X(L1r49)*STPNOM+( < < <0,03.+ A(94) )*A< 173) ) - l )*Z(35) ) 157 IF(NTIME.GE.NSTAR1) Y(49)=X<LI,49)*STPNOM+< (((0.03+A(94))*A<173))-l)*Z(35)) 158 l+(,05*Z(34))+Z(48) 159 IF(K7.EQ.NYEAR) Y(49 ) =Z(49)/Z(99) 160 Y<50) = ( (Z(49)/Z(3) )*< ( ( A ( 94 ) **25 ) - < A (.94 ) **2 4))/ 161 1((A(94)**20)-l)))*1000 162 C COST OF L. P. PER MCF . 163 IF(NTIME.LT.NSTARl) Y(51)=X(L1»51)*STPNOM+( (((0.03+A(94))*A(173))-l)*Z(37)) 164 IF(NTIME.GE.NSTARl) Y(51)=X(L1»51)*STPNOM+( (((0.03+A(94>)*A(173))-l)*Z(37>) 165 l+(.05*Z(36))+Z(47) 166 IF < K7.EQ•NYEAR) Y(51)=Z(51)/Z(99) 167 Y(52)=((Z(51)/Z(3))*(((A(94)**25)-(A(94)**2 4) )/ | 168 1((A(94)**20)-l)))*1000• i 169 C COST OF SHIPPING PER MCF 170- IF(NTIME.LT•NSTAR1 ) Y(53)=X(LI?53)*STPNDM+( ( ( (0.03+A.(94) )*A(173) ) - l )*Z(39) ) - 5 8 -171 IFCNTIME.GE.NSTARl) Y<53)=X(LIf53)*STPNOM+< ((<0.03+A(94))*A(173))-l)*Z(39)) 172 l+<.05*Z(38))+Z<46) 173 Y(54) = ((Z(53)/Z(3) )*(((A(94>#*25)-(A(94)**2 4) )/ 174 1((A(94)**20)-l)))*1000 175 C PRICE OF FEED ESCALATED 176 A(128)=A(50)/1000 177 IF(NTIME.EQ.NSTARl-S) Y(55)=A<128) 178 IF(NTIME.GT.NSTAR1~5) Y(55)=X<LIr55)*A(173) *A<169> 179 C PRICE OF FEED AS FUEL(ESCALATED) 180 A(131)=A(51)/1000 181 IF(NTIME.EQ.81) Y(56)=A(131) 182 IFCNTIME.GT.81) Y(56)=X(LIt56)*A(173)*A(169 ) 183 C ANNUAL QUANTITY OF N.G. PURCHASED 184 Y(58)=E(K»1)*Z(2)*A(40) 185 C SOCIAL COST OF THE NATURAL GAS 186 C SOCIAL VALUE 187 IF(NTIME.EG.81) Y(59)=A(44) 188 IF(NTIME.GT.81) Y(59)=X(LI,59)*A(173)*A(169 ) 189 C P. V. OF NAT. GAS PRICED AT SOCIAL VALUE 190 Y(60)=Z(59)*Z(58) 191 Y<61)=X(L1,61)*STPN0M+Z<60) 192 IF(K7.EG.NYEAR) Y(61)=Z(61)/Z(99) 193 C COST OF FEED 194 Y<62)=Z<55)*Z<58)*A<41) 195 C P.V. OF COST OF FEED 196 - Y(63)=STPN0M*X(L1f63)+Z<62) . 197 IF (K7..EQ. NYEAR) Y < 63 ) =Z < 63)/Z ( 99 ) 198 C COST OF FEED PER MCF PRODUCED 199 IF<NTIME.LT.NSTAR1 ) Y(64)=0 200 IF(NTIME.GE.NSTARl) Y(64)=(Z(63>/Z(4))*1000 201 C COST OF FEED FOR LIQUEFACTION(FUEL) 202 Y(65)=Z(56)*Z<58)*A<42) 203 C PRESENT VALUE OF FUEL FOR LIQUEFACTION 204 IF(NTIME.LT« NSTAR1 ) Y<66)=0 205 IF(NTIME.GE.NSTAR1) Y(66)=X(LIr66)*STPNOM+Z (65) 206 IF < K7.EQ•NYEAR) Y<66)=Z<66)/Z(99) 207 C COST OF FUEL FOR LIQUE. PER MCF IN 81$ 208 Y(67) = < <Z(66)/Z<3))*(< <A(94)**25)-<A<94)**2 4) )/ 209 1<(A(94)**20)-l)))*1000 210 C COST OF FEED FOR SHIPPING(FUEL) 211 Y(68)=Z(56)*Z(58)*A<43) 212 C PRESENT VALUE OF FUEL FOR SHIPPING 213 IF(NTIME.LT.NSTARl) Y(69>=0 214 IF(NTIME.GE.NSTARl) Y<69)=X(LI,69)*STPNOM+Z (68) 215 IF(K7,EQ.NYEAR) Y(69)=Z(69)/Z(99) 216 C COST OF FUEL FOR SHIPPING PER MCF IN 81$ 217 Y(70)=<(Z(69)/Z(3))*(<(A<94)**25)-(A(94)**2 4) )/ 218 1((A(94)**20)-l)))*1000 J -59-2 1 9 2 2 0 2 2 1 2 2 3 2 2 4 2 2 5 2 2 6 2 2 7 2 2 8 2 2 9 2 3 0 2 3 1 2 3 2 2 3 3 2 3 4 2 3 5 2 3 6 ,237 2 3 8 2 3 9 2 4 0 2 4 1 2 4 2 2 4 3 2 4 4 2 4 5 2 4 6 2 4 7 2 4 8 2 4 9 2 5 0 2 5 1 2 5 2 2 5 3 2 5 4 2 5 6 2 5 7 2 5 8 2 5 9 2 6 0 2 6 1 2 6 2 2 6 3 2 6 4 2 6 5 2 6 6 2 6 7 2 6 8 2 6 9 C T O T A L C O S T OF N A T , G A S Y ( 7 1 ) = Z ( 6 2 ) + Z < 6 5 ) + Z ( 6 8 ) C T O T A L COST OF F E E D AND' O P E R A T I N G C O S T S Y ( 7 2 ) = Z ( 4 6 ) + Z ( 4 7 ) + Z ( 4 8 ) + Z " ( 7 1 ) C C O S T OF D E B T F I N A N C I N G Y ( 7 3 ) = ( ( A ( 9 4 ) * A ( 1 7 3 ) ) - 1 ) * A ( 1 3 2 ) # X ( L I y 3 0 ) C P R E S E N T V A L U E OF C O S T OF D E B T Y ( 7 4 ) = X ( L 1 y 7 4 ) * S T P N 0 M + Z ( 7 3 ) I F ( K 7 . E Q . N Y E A R ) Y ( 7 4 ) = Z ( 7 4 ) / Z ( 9 9 ) C C O S T OF E Q U I T Y F I N A N C I N G Y < 7 5 ) = < < A ( 9 4 ) * A ( 1 7 3 ) ) - ! ) * < 1 - A < 1 3 2 ) ) * X < L 1 » 3 0 ) C P . V C O S T S C C C L OF T O T A L F I N A N C I N G Y ( 7 6 ) = Z ( 7 3 ) + Z ( 7 5 ) Y ( 7 7 ) = X < L I y 7 7 ) * S T P N O M + Z ( 7 6 ) I F < K 7 . E Q . N Y E A R ) Y ( 7 7 ) = Z ( 7 7 ) / Z ( 9 9 ) F E D , D E F OF N O N - D E P R C A P . S T O C K P I P E L I N E Y ( 7 8 ) = A ( 8 5 ) * ( X ( L 1 y 7 8 ) + Z ( 2 4 ) ) S H I P S Y ( 7 9 ) = A ( 8 6 ) * ( X ( L 1 y 7 9 ) + Z ( 2 6 ) ) P L A N T Y < 8 0 ) = A ( 8 7 ) * ( X ( L l y 8 0 ) + ( A ( 1 2 5 ) * Z ( 2 5 ) ) ) Y ( 8 1 > = A ( 8 8 ) * ( X ( L l y 8 1 ) + ( A ( 1 2 6 ) * Z ( 2 5 > ) ) Y ( 8 2 ) = A ( 1 1 7 ) * ( X ( L l y 8 2 ) + ( A ( 1 2 7 ) * Z < 2 5 > >) C D E P R E C I A T I O N ALLOWED Y ( 8 3 ) = Z ( 7 8 ) + Z ( 7 9 ) + Z ( 8 0 ) + Z ( 8 1 ) + Z ( 8 2 ) Y ( 8 4 ) = ( X ( L l y 8 2 ) + Z ( 2 7 ) - Z ( 8 3 ) ) * A ( 5 8 ) C P R E S E N T V A L U E OF C C A Y ( 8 5 ) = X ( L l r 8 5 ) * S T P N 0 M + Z < 8 4 ) I F ( K 7 . E Q . N Y E A R ) Y < 8 5 ) = Z ( 8 5 ) / Z ( 9 9 ) C F E D D E F OF T A X A B L E I N C O M E Y ( 8 6 ) = Z ( 7 ) - Z ( 7 2 ) - Z ( 8 4 ) - Z ( 7 3 ) C F E D . T A X P A Y A B L E Y ( S 7 ) = . 3 6 * Z ( 8 6 ) C P R O V . T A X Y ( 8 8 ) = . 1 3 * Z < 8 6 ) C P R E S E N T V A L U E OF T O T A L T A X E S ; Y < 8 9 ) = X ( L 1 , 8 9 ) * S T P N O M + Z < 8 7 ) + Z < 8 8 ) - < X ( L 1 y 5 5 ) * ( . 0 3 * A < 1 7 3 ) ) ) I F < K 7 . E Q . N Y E A R ) Y ( 8 9 ) = Z ( 8 9 ) / Z ( 9 9 ) C P R E S E N T V A L U E OF T H E P R O J . TO T H E F I R M I F ( N T I M E . L T . N S T A R l ) Y ( 9 0 ) = X ( L I y 9 0 ) * S T P N O M - Z ( 7 3 ) - Z ( 8 7 ) - Z ( 8 8 ) - Z ( 7 5 ) I F < N T I M E . G E . N S T A R 1 ) Y ( 9 0 ) = X ( L I y 9 0 ) * S T P N O M + Z < 7 ) - Z ( 7 2 ) - Z ( 7 3 ) - Z ( 7 5 > -l Z ( B 7 > - Z ( 8 8 ) - ( . 0 5 * Z ( 2 8 ) ) I F ( K 7 . E Q • N Y E A R > Y ( 9 0 ) = Z ( 9 0 ) / Z ( 9 9 ) C P R E S E N T V A L U E TO THE G O V E R N M E N T Y ( 9 1 ) = Z ( 8 9 ) - ( Z ( 7 1 ) - Z ( 6 0 ) ) C V A L U E OF THE N A T U R A L G A S I N T H I S U S E C S O C I A L V A L U E Y ( 9 2 ) = Z ( 9 3 ) * < < A ( 9 4 ) * * 2 5 ) - < ( A < 9 4 ) * * 2 4 ) * A < 1 6 9 )>)*1000 Y ( 9 3 ) = X ( L 1 » 9 3 ) * S T P N 0 M + Z ( 7 ) - Z ( 4 6 ) - Z ( 4 7 ) - Z ( 4 8 ) - Z ( 7 3 ) - Z ( 7 5 ) l - < . 0 5 * Z ( 2 8 ) * E ( K , 1 ) ) - ( . 0 3 * A ( 1 7 3 ) * X ( L l r 3 0 ) ) - 6 0 -I F ( K 7 . E Q . N Y E A R ) Y ( 9 3 > = ( Z ( 9 3 ) / Z ( 9 V ) ) I F ( K 7 . L T . N Y E A R ) Y ( 9 4 > = 0 I F ( K 7 . E Q . N Y E A R ) Y ( 9 4 ) = Z ( 9 2 ) / < < Z ( 5 8 ) * ( A < 1 6 9 ) * * 5 ) 1 * ( A ( 9 4 ) * * 2 0 ) ) - ( Z ( 5 8 ) * ( A ( 1 6 9 ) * * 2 5 ) ) ) C P R I V A T E V A L U E Y ( 9 5 ) = ( ( . 5 1 * Z < 8 ) ) - ( . 5 1 * Z ( 9 7 ) ) - Z ( 7 7 ) - Z ( 3 2 ) l + ( . 4 9 * Z < 8 5 ) ) + ( . 4 9 * Z ( 7 4 ) ) ) / . 5 1 I F ( K 7 . L T . N Y E A R ) Y ( 9 6 ) = 0 I F ( K 7 . E Q , N Y E A R ) Y ( 9 6 ) = ( ( Z ( 9 5 ) * ( ( A ( 94.) * * 2 5 ) -( ( A ( . 9 4 > * * 2 4 > * 1 A ( 1 6 9 ) ) ) ) / ( Z ( 5 8 ) * ( ( A ( 9 4 ) * * 2 0 ) * ( A ( 1 6 9 ) * * 5 ) - ( A < 1 6 9 ) * * 2 5 ) ) ) ) * 1 0 0 0 C P R E S E N T V A L U E OF O P E R A T I N G C O S T S Y ( 9 7 ) = X ( L 1 » 9 7 ) * S T P N 0 M + Z ( 4 6 ) + Z ( 4 7 ) + Z ( 4 B ) I F ( K"7 . EG . N Y E A R ) Y ( 9 7 ) = Z ( 9 7 ) / Z ( 9 9 ) R E T U R N END S U B R O U T I N E CONS1 C C D N S 1 I S ONLY U S E D FOR P R O D U C T I O N S T A R T C L N G MODEL C O M M O N / K E E P / L A B X ( 2 s > 8 0 0 ) H_ABE(2«600) » D A T E < 1 0 0 ) » D U M < 3 0 ) » T E S T < 8 0 0 ) t 1 T I T L E ( 2 0 ) 5 - 7 ( 8 0 0 ) , TEMP ( 8 0 0 ) * A ( 3 0 0 0 ) * X < 7 * 8 0 0 ) r E < 7 * 6 0 0 ) C 0 M M 0 N / S A V E / K * K 1 t K7» M»NED»NEX»NT»NL »NC»NDRR E G . -1NDRSHK»M7 »M8•MAX ? N C O N T R , N C O N V , N S K I P ? N P O L ?NY E A R ? N R E V A f N R D A T A f 2C0NVG»N2.ID»NUMSXfNUMSE C O M M O N / L L L / L 1 » L 2 , L 3 ? L..4 , L 5 r L 6 , L 7 ~ COMMON A R G ( 2 0 0 ) » P H I A ( 2 0 0 ) i P H I G H < 2 5 ) , A R E A ( 2 0 0 ) L O G I C A L DUM I N T E G E R T I T L E ? D A T E D I M E N S I O N L 0 ( 7 ) r Y ( 8 0 0 ) , Y P ( B O O ) E Q U I V A L E N C E ( Y , Z ) , ( L O , L 1 , L ) N T I M E = I D - 1 9 0 1 + K 7 M D = I F I X < A < 1 0 5 ) ) N T I M D = N T I M E - M D N S T A R 1 = I F I X ( A < 1 6 2 ) ) L I F E = I F I X ( A ( 1 5 9 ) ) N Y E A R = N S T A R 1 - 8 1 + L I F E R T I M E = N T I M E R S T A R 1 = N S T A R 1 R L I F E = L I F E I F ( N T I M E • E Q . 8 1 ) S T P N O M = A ( 9 4 ) * A ( 1 7 3 ) I F ( N T I M E . G T . 8 1 ) S T P N O M = A ( 9 4 ) * A ( 1 7 3 ) C P R O D U C T I O N S T A R T I F ( N T I M E . L T . N S T A R l ) E ( K F 1 ) = 0 . 0 I F ( N T I M E . G E . N S T A R 1 ) E ( K > 1 ) = 1 . 0 R E T U R N END N \ 

Cite

Citation Scheme:

        

Citations by CSL (citeproc-js)

Usage Statistics

Share

Embed

Customize your widget with the following options, then copy and paste the code below into the HTML of your page to embed this item in your website.
                        
                            <div id="ubcOpenCollectionsWidgetDisplay">
                            <script id="ubcOpenCollectionsWidget"
                            src="{[{embed.src}]}"
                            data-item="{[{embed.item}]}"
                            data-collection="{[{embed.collection}]}"
                            data-metadata="{[{embed.showMetadata}]}"
                            data-width="{[{embed.width}]}"
                            async >
                            </script>
                            </div>
                        
                    
IIIF logo Our image viewer uses the IIIF 2.0 standard. To load this item in other compatible viewers, use this url:
http://iiif.library.ubc.ca/presentation/dsp.831.1-0095052/manifest

Comment

Related Items