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An application of marginal cost pricing principles to B.C. Hydro 1977

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AN APPLICATION OF MARGINAL COST PRICING PRINCIPLES TO B. C. HYDRO by SANFORD LAKE OSLER B.A. U n i v e r s i t y o f T o r o n t o , 1971 A T h e s i s Submitted i n P a r t i a l F u l f i l l m e n t o f The Requirements f o r the Degree o f Master o f A r t s The F a c u l t y o f Graduate S t u d i e s Department o f Economics U n i v e r s i t y o f B r i t i s h Columbia We a c c e p t t h i s t h e s i s as c o n f o r m i n g to the r e q u i r e d s t a n d a r d The U n i v e r s i t y o f B r i t i s h Columbia June, 1977 (^c^Sanford Lake Osier, 1977 i n In p r e s e n t i n g t h i s t h e s i s in p a r t i a l f u l f i l m e n t o f the requ i rement s f o r an advanced degree at the U n i v e r s i t y o f B r i t i s h Co lumb ia , I ag ree that 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 tudy . 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 r e p r e s e n t a t i v e s . It i s u n d e r s t o o d that c o p y i n g o r p u b l i c a t i o n o f t h i s t h e s i s f o r f i n a n c i a l g a i n s h a l l not be a l l o w e d w i thout my w r i t t e n p e r m i s s i o n . Department o f F m n r m i n 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 Place Vancouver, Canada V6T 1W5 Date June 24, 1977 ABSTRACT The purpose of t h i s paper i s t o develop and apply a methodology to determine the marginal economic c o s t s of s u p p l y i n g e l e c t r i c i t y i n the predominantly h y d r o - e l e c t r i c system of the B r i t i s h Columbia Hydro and Power A u t h o r i t y (B.C. Hydro). T h i s i n f o r m a t i o n i s used to design an economically e f f i c i e n t r a t e s t r u c t u r e i n which marginal p r i c e i s set egual t o marginal economic c o s t . The r e s u l t i n g i m p l i c a t i o n s f o r the growth r a t e i n e l e c t r i c a l demand and c o s t s are then c a l c u l a t e d . A computer s i m u l a t i o n model i s b u i l t which, once given a demand f o r e c a s t to 1990, plans and operates the e l e c t r i c system i n a c o s t minimizing f a s h i o n s u b j e c t t o t e c h n i c a l c o n s t r a i n t s and the op e r a t i n g p o l i c i e s of B.C. Hydro. The a s s o c i a t e d annual accounting c o s t s are determined and the r a t e l e v e l s adjusted i n accordance with the A u t h o r i t y ' s f i n a n c i a l p o l i c i e s . Marginal economic c o s t s are c a l c u l a t e d by i n t r o d u c i n g v a r i o u s a l t e r a t i o n s t o the demand f o r e c a s t and examining the i m p l i c a t i o n s f o r the present value of economic c o s t s of such changes. These amounts, when d i v i d e d by the g u a n t i t y of e l e c t r i c i t y i n v o l v e d , give e s t i m a t e s of the u n i t c o s t s of a change i n energy and/or peak demand f o r v a r i o u s c l a s s e s of customers. These marginal economic c o s t s are then i n c o r p o r a t e d i n a redesigned r a t e s t r u c t u r e i n which marginal p r i c e s egual these marginal c o s t s while average p r i c e s continue to egual average accounting c o s t s . By a p p l y i n g v a r i o u s estimates of long run own price e l a s t i c i t y of demand, the impact on demand growth caused by marginal price changes can be determined. This nes demand forecast w i l l , i n turn, af f e c t system design and operation and thus ultimately, costs. The res u l t of th i s analysis i s that the larger users (both within each class and within the system) face sub s t a n t i a l l y higher marginal rates from those now in ef f e c t . In p a r t i c u l a r , the economic analysis attaches far greater weight to the energy component of demand i n the e n e r g y - c r i t i c a l B.C. Hydro system than does the accounting approach. Under the median e l a s t i c i t y estimates, t h i s rate structure reform reduces the e l e c t r i c a l growth rate from 9.0 to 7.0 percent i n the 1976-1990 period, reduces average r e a l accounting costs from 18.1 to 16.5 mills per KWH, and reduces the gross debt outstanding i n 1990 from 17.1 to 11.2 b i l l i o n h i s t o r i c d o l l a r s . We conclude that there e x i s t s substantial gains in s o c i a l welfare to be obtained from redesigning B.C. Hydro's e l e c t r i c a l rate structures. i v TABLE OF CONTENTS ^• X n t i r o c i i i c t i o i i • • * * • • • * * • • * * • • • *••'*••»**.••*.••*'•'*•• 1 2. B.C. Hydro Today 4 2 • 1 I n t r o d u c t i o n • • • ** * • * * • * •- • • * • ••** • • • * • • * • » * * 4 2.2 Past And Present P o l i c i e s Of The E l e c t r i c S e r v i c e ...6 2.3 Summary ..........25 3. Theory And Methodology Of Marginal Cost P r i c i n g ........27 3.1 Emergence Of The Theory Of M.C.P. . 27 3.2 Emergence Of The Methodology And A p p l i c a t i o n Of M.C.P. ........................................32 3.3 Developing An M.C.P. Methodology For B.C. Hydro 35 3.4* Summary ....... .... ............ .... ...... ............ i*5 4. The S t r u c t u r e Of The Model ....... 46 4.1 I n t r o d u c t i o n ....46 4.2 POLD1 And P0LS1 .......... ......... 48 4 . 3 DEMAND 50 ^ • 4' S Ul? P I J Y " • • • • • * * * - • • • • • • • • * . * « * * • ••••5'1 4.5 MCOST 56 4.6 APPROVE .............................................62 4.7 COSTS 63 4.8 BATES ........69 5. The Re s u l t s ......70 5.1 P r o j e c t C o s t i n g And Ranking ......................... 70 5.2 Conventional Accounting P r o j e c t i o n s 77 5.3 Determination Of Mar g i n a l Cost ......................87 6. A p p l i c a t i o n s ...........................................97 6.1 Rate S t r u c t u r e Design .97 6.2 Demand And System Response 104 7. Summary And Con c l u s i o n s ................115 B i b l i o g r a p h y ..119 A. Appendix A .........127 B. Appendix B 128 C. Appendix C ....129 D. Appendix D ............................................. 136 D.1 L i s t Of V a r i a b l e s , C o e f f i c i e n t s , And D e f i n i t i o n s ....136 D.2 O u t l i n e Of B.C. Hydro Model ......................... 146 v i LIST OF TABLES Table 1: C o s t i n g Of Generation P r o j e c t s ..........71 Table 2: 1976-1990 P r o j e c t i o n Of Key F i n a n c i a l V a r i a b l e s ..79 Table 3: S e n s i t i v i t y A n a l y s i s On Average Cost/KWH In The 1976-1990 Pe r i o d ....................................... 81 Table 4: R e l a t i v e Cost Changes: 1 976-1990 . .. . . 83 Table 5: Ma r g i n a l Economic Co s t s For Various Demand Shocks 89 Table 6: A Survey Of Estimated Long Hun Own P r i c e E l a s t i c i t i e s Of E l e c t r i c i t y Demand ......108 Table 7: I m p l i c a t i o n s Of Rate S t r u c t u r e Reform ............111 Table 8; Marginal And Average P r i c e s Of E l e c t r i c i t y .......117 Table C-1: Impact On B.C. Hydro Of A l t e r n a t i v e Rate S t r u c t u r e s 130 Table C-2: Impact On Customers Of A l t e r n a t i v e Rate S t r u c t u r e s ..........134 LIST OF FIGURES F i g u r e 1 ..................................................98 ACKNOWLEDGEMENTS I am deeply i n d e b t e d t o many f o r a s s i s t a n c e i n the p r e p a r a t i o n of t h i s paper. John H e l l i w e l l p r o v i d e d the general guidance, i n s p i r a t i o n and co n f i d e n c e which made i t a l l p o s s i b l e . Gerry May i n t r o d u c e d me to the world of computer modelling and served as an i n v a l u a b l e sounding board during the c o n c e p t u a l i z a t i o n p e r i o d . , E r n i e Berndt provided a s s i s t a n c e with l a t e r stages and c a r e f u l l y reviewed p r e l i m i n a r y d r a f t s . C h e e r f u l and e f f i c i e n t s e c r e t a r i a l and t e c h n i c a l s e r v i c e s were provided by Janey G i n t h e r . A v a r i e t y of o f f i c i a l s at B.C. Hydro gave f r e e l y of t h e i r time t o help me understand t h e i r u t i l i t y and to review an i n i t i a l d r a f t . Not l e a s t important, the O f f i c e of Energy Conservation w i t h i n the f e d e r a l Department of Energy, Mines and Resources provided f i n a n c i a l and moral support throughout the r e s e a r c h i n g and w r i t i n g o f t h i s t h e s i s . Many thanks to you a l l . 1 INTRODUCTION In r e c e n t years, there has been growing p u b l i c concern about the a c t i o n s and p o l i c i e s of many North American e l e c t r i c u t i l i t i e s . Much of the c r i t i c i s m has centred around the high growth r a t e s p r o j e c t e d by these u t i l i t i e s and the means proposed to f u l f i l t h i s f o r e c a s t demand. Con s i d e r a b l e a t t e n t i o n has been paid to t h e i r r a t e s t r u c t u r e s with some c r i t i c s h o l d i n g them r e s p o n s i b l e f o r " e x c e s s i v e " growth r a t e s . Most e l e c t r i c u t i l i t i e s i n North America long ago adopted a d e c l i n i n g block r a t e s t r u c t u r e . T h i s meant t h a t , both w i t h i n and between c l a s s e s of customers, the g r e a t e r the consumption the lower the u n i t p r i c e of e l e c t r i c i t y . Although now u s u a l l y l e s s pronounced, t h i s format remains predominant and i s j u s t i f i e d by the u t i l i t i e s as being " c o s t based". The purpose of t h i s paper w i l l be to use economic a n a l y s i s to suggest an a p p r o p r i a t e r a t e s t r u c t u r e f o r one p a r t i c u l a r u t i l i t y , B.C. Hydro. Although the primary emphasis w i l l be on developing and a p p l y i n g a methodology f o r determining and a l l o c a t i n g economic c o s t s , c o n s i d e r a t i o n w i l l a l s o be given t o the i m p l i c a t i o n s t h a t the r e s u l t i n g e c o n o m i c a l l y a p p r o p r i a t e r a t e s t r u c t u r e s have f o r demand growth. The primary c r i t e r i o n t h a t w i l l be employed i n desig n i n g t h i s r a t e s t r u c t u r e i s t h a t o f economic e f f i c i e n c y . T h i s means that a necessary c o n d i t i o n f o r the e f f i c i e n t a l l o c a t i o n o f resources and the maximization of s o c i a l welfare i s t h a t the marginal p r i c e o f a product must egual i t s marginal s o c i a l c o s t of production. Much, of t h i s paper w i l l f o c u s on how best t o determine the marginal c o s t s a s s o c i a t e d with s u p p l y i n g 2 e l e c t r i c i t y . The s e l e c t i o n of B.C. Hydro as the case study was i n f l u e n c e d , n a t u r a l l y , by i t s geographic p r o x i m i t y . There were many reasons, however, which make i t au i d e a l c andidate f o r a n a l y s i s . B.C. Hydro's f o r e c a s t growth r a t e f o r e l e c t r i c i t y i s one o f the h i g h e s t on the c o n t i n e n t , and i t s expansion plans a re running i n t o i n c r e a s i n g o p p o s i t i o n throughout the prov i n c e . An independent a n a l y s i s o f the ap p r o p r i a t e n e s s of i t s r a t e s t r u c t u r e c o u l d help to c l a r i f y some the i s s u e s being d i s c u s s e d . Secondly, the very nature of the B.C. Hydro system, with i t s e x i s t i n g and growing heavy r e l i a n c e on h y d r o - e l e c t r i c g eneration sources, presented s p e c i a l o p p o r t u n i t i e s . While t h i s type of system i s unusual i n a world context, i t i s c h a r a c t e r i s t i c of s e v e r a l other important Canadian e l e c t r i c u t i l i t i e s . I t has been suggested ( f a l s e l y ) t h a t marginal c o s t analyses of predominantly h y d r o - e l e c t r i c systems are p a r t i c u l a r l y d i f f i c u l t t o perform. To the best of my knowledge, none has been done to d a t e . 1 F i n a l l y , the p u b l i c a v a i l a b i l i t y of s e v e r a l r e c e n t e x t e n s i v e p u b l i c a t i o n s by B.C. Hydro has provided me with s u f f i c i e n t t e c h n i c a l i n f o r m a t i o n t o undertake t h i s a n a l y s i s . In a d d i t i o n , the ready c o - o p e r a t i o n , a s s i s t a n c e and i n t e r e s t o f many Hydro o f f i c i a l s i n a v a r i e t y of areas c o n t r i b u t e d g r e a t l y to my understanding of the u t i l i t y . The next chapter c o n t a i n s a d e s c r i p t i o n of B.C. Hydro as i t c u r r e n t l y e x i s t s , i n c l u d i n g a review of the way i n which i t f o r e c a s t s e l e c t r i c a l demand, determines i t s expansion programme, 1 See, f o r example, Barnett (1977). 3 f i n a n c e s i t s growth and s e t s r a t e s . The t h i r d chapter examines what economic theory suggests i n the way of a p p r o p r i a t e r a t e s t r u c t u r e s , assesses v a r i o u s methodologies t h a t have been developed to a l l o c a t e c o s t s , and o u t l i n e s the approach t o be employed i n t h i s a n a l y s i s . The f o l l o w i n g two ch a p t e r s d e t a i l t he model t h a t i s used and present the co s t a l l o c a t i o n r e s u l t s t h a t i t generates. The s i x t h chapter examines some of the i m p l i c a t i o n s and a p p l i c a t i o n s of these r e s u l t s - f o r the design of the r a t e s t r u c t u r e , and f o r the f o r e c a s t i n g of f u t u r e demand. The c o n c l u d i n g chapter b r i e f l y summarizes the main r e s u l t s of t h i s paper and comments on the r e l e v a n c e and l i k e l i h o o d of acceptance of the u n d e r l y i n g p r i n c i p l e s . a ZJL B.C. HYDRO TODAY 2.1 I n t r o d u c t i o n B r i t i s h Columbia Hydro and Power A u t h o r i t y was c r e a t e d as a Crown c o r p o r a t i o n by the government of B r i t i s h Columbia i n 1962. I t was formed by the amalgamation of two e l e c t r i c u t i l i t i e s then s e r v i n g d i f f e r e n t areas i n B.C.: the privately-owned B r i t i s h Columbia E l e c t r i c Company L i m i t e d and the Crown c o r p o r a t i o n B r i t i s h Columbia Power Commission. The o r i g i n a l l e g i s l a t i o n was held to be i n v a l i d by the Supreme Court of B r i t i s h Columbia, but the union was f o r m a l l y cemented with the passage i n 1964 of the B r i t i s h Columbia Hydro and Power Au t h o r i t y Act. Under t h i s Act, B.C. Hydro was given broad powers and has developed an e x t e n s i v e system of p u b l i c u t i l i t y s e r v i c e s . At present i t operates a r e g i o n a l gas d i s t r i b u t i o n system, an i n t e r - and i n t r a - c i t y bus passenger s e r v i c e , a s m a l l f r e i g h t r a i l w a y and t h r e e dams i n connection with the Columbia River Treaty. By f a r i t s l a r g e s t r e s p o n s i b i l i t i e s , however, l i e i n the e l e c t r i c s e r v i c e area. B.C. Hydro i s the t h i r d l a r g e s t e l e c t r i c u t i l i t y i n Canada, s e r v i n g an area c o n t a i n i n g more than 90 percent o f the p o p u l a t i o n of B r i t i s h Columbia. The p r o v i n c i a l government has never f o r m a l l y d e f i n e d the b a s i c mandate or formal o b j e c t i v e s of B.C. Hydro. The A u t h o r i t y has i t s e l f r e c e n t l y s t a t e d that the t y p i c a l f u n c t i o n of a p u b l i c l y owned u t i l i t y might be summarized as f o l l o w s : 5 To supply t h e demands of i t s customers f o r energy a t the lowest c o s t c o n s i s t e n t with s a f e t y to i t s employees and p u b l i c , good q u a l i t y of s e r v i c e to i t s customers, and s u b j e c t t o the s o c i a l , economic and environmental p o l i c i e s of the Government. (B.C. Hydro, 1975b, 12) F i n a l decision-making a u t h o r i t y w i t h i n B.C. Hydro i s vested with a Board of D i r e c t o r s , c u r r e n t l y c o n s i s t i n g of f i v e members i n c l u d i n g the p r o v i n c i a l c a b i n e t m i n i s t e r r e s p o n s i b l e f o r energy. The A u t h o r i t y has f u l l power to determine the r a t e s charged f o r i t s s e r v i c e s . Only i n the case of one r a i l w a y l i n e and o f e l e c t r i c i t y and n a t u r a l gas s o l d o u t s i d e the province are these p r i c e s s u b j e c t to e x t e r n a l a p p r o v a l . 2 I n the case of s p e c i f i c p r o j e c t s t h a t B.C. Hydro seeks to undertake, a p p r o v a l may be r e q u i r e d from the a p p r o p r i a t e e x t e r n a l a u t h o r i t i e s . B.C. Hydro i s s u b j e c t t o a l l f e d e r a l taxes except taxes on income and c a p i t a l . I t g e n e r a l l y pays the e q u i v a l e n t of the same l o c a l and p r o v i n c i a l taxes as any other c o r p o r a t i o n , with t h e exception of a s p e c i a l s c h o o l tax exemption on i t s b i g g e s t h y d r o - e l e c t r i c g enerating i n s t a l l a t i o n s . I t s bonds and other s e c u r i t i e s are u n c o n d i t i o n a l l y guaranteed by the Province of B r i t i s h Columbia. As of March 31, 1976, B.C. Hydro's t o t a l a s s e t s stood a t s l i g h t l y over $4 b i l l i o n . Of t h i s , more than $3 b i l l i o n was f i n a n c e d through bonds i s s u e d or acquired by the A u t h o r i t y . B.C. Hydro's revenues i n the 1975-76 f i s c a l year s l i g h t l y exceeded i t s expenses, but only a f t e r a s p e c i a l subsidy from the 2 The B r i t i s h Columbia Energy Commission i s empowered to review c e r t a i n d i s c r i m i n a t i o n complaints and the p r o v i n c i a l government in t e n d s to e s t a b l i s h a permanent L e g i s l a t i v e Committee to examine the l a r g e Crown c o r p o r a t i o n s . 6 p r o v i n c i a l government to cover the l o s s a s s o c i a t e d with bus t r a n s i t o p e r a t i o n s (see appendix A) . 2.2 Past And Present P o l i c i e s Of The E l e c t r i c S e r v i c e 2.2.1 Demand f o r E l e c t r i c i t y U n t i l r e c e n t l y , the e l e c t r i c s e r v i c e of B.C. Hydro has experienced r e l a t i v e l y r a p i d growth i n the demand f o r i t s product. At t h i s stage i t i s important to d i s t i n g u i s h c l e a r l y between the energy and peak demand components of t h i s growth. The demand f o r e l e c t r i c a l energy r e f l e c t s the t o t a l energy reguirements i n a given time p e r i o d {say one year) without regard to the r a t e of use of t h a t energy w i t h i n the s p e c i f i e d time p e r i o d . I t i s measured i n k i l o w a t t - h o u r s . Peak demand, on the other hand, r e f l e c t s the maximum r a t e of energy consumption i n a given time p e r i o d ( u s u a l l y one hour). I t i s measured i n k i l o w a t t s . The two concepts are r e l a t e d through the l o a d f a c t o r , a r a t i o of the average demand i n k i l o w a t t s s u p p l i e d d u r i n g a designated p e r i o d t o the maximum demand o c c u r r i n g i n t h a t p e r i o d . Throughout t h i s paper the demand f o r e l e c t r i c i t y (or lo a d demand) w i l l be used i n the ge n e r a l economic sense and r e f e r t o both components of e l e c t r i c a l demand, while the energy or peak demand terminology w i l l be used when r e f e r r i n g s p e c i f i c a l l y t o e i t h e r component.? Since i t s for m a t i o n i n 1962, B.C. Hydro's s a l e s of 3 T h i s d i s t i n c t i o n i s c a r e f u l l y made here because of the common usage of the term "demand" i n the e l e c t r i c a l l i t e r a t u r e t o r e f e r only to what I have c a l l e d "peak demand". 7 e l e c t r i c a l energy to the p u b l i c have i n c r e a s e d from 5.5 to 20.6 b i l l i o n k i l o w a t t hours, an average annual compounded growth r a t e of 9.8 percent. Over t h i s same p e r i o d , the peak one-hour demand has had an annual growth r a t e o f 9.4 percent, expanding from 1.2 to 4.1 m i l l i o n k i l o w a t t s . Annual i n c r e a s e s i n e l e c t r i c a l energy consumption exceeding ten percent took place i n the 1965-1970 p e r i o d and again i n 1973 and 1974, with a c t u a l r e d u c t i o n s o c c u r r i n g i n 1975 and 1976. At present, consumption o f e l e c t r i c a l energy i s f a i r l y evenly s p l i t among the t h r e e major customer c l a s s e s : r e s i d e n t i a l , g eneral and bulk. The general c l a s s comprises a l l commercial customers p l u s the s m a l l e r i n d u s t r i a l u s e r s , whereas the bulk c l a s s c o n t a i n s l a r g e i n d u s t r i a l consumers. In the past,net energy s a l e s to other e l e c t r i c a l systems have u s u a l l y represented l e s s than 5 percent of t o t a l s a l e s . * During the 1962-1976 p e r i o d , the share of the t o t a l B.C. energy market s u p p l i e d by e l e c t r i c i t y rose s l i g h t l y and now stands a t c l o s e to 18 percent. O i l c o n t i n u e s to supply j u s t over h a l f of the t o t a l p r o v i n c i a l market, f o l l o w e d by n a t u r a l gas with 20 percent and then e l e c t r i c i t y . B.C. Hydro's share of the e l e c t r i c i t y market has grown from l e s s than h a l f t o i t s present 65 percent of the p r o v i n c i a l t o t a l . Although s u p p l y i n g the v a s t majority of r e s i d e n t i a l and commercial customers, the A u t h o r i t y does not provide e x c l u s i v e s e r v i c e to a s i g n i f i c a n t p a r t o f the l a r g e i n d u s t r i a l market which has b u i l t s u b s t a n t i a l hydro- * In 1974 a r e c o r d share of 10 per cent of t o t a l s a l e s went t o other systems due to e x c e p t i o n a l l y dry c o n d i t i o n s i n these other areas. 8 e l e c t r i c or wood waste g e n e r a t i n g c a p a c i t y . s P a r t of t h i s e nlarged share of the e l e c t r i c i t y f i e l d i s accounted f o r by B.C. Hydro's a c q u i s i t i o n of t e n s m a l l e l e c t r i c u t i l i t i e s d uring t h i s p e r i o d . In f o r e c a s t i n g f u t u r e demand growth, B.C. Hydro r e l i e s on the methodology i t c l a i m s to have employed s u c c e s s f u l l y i a the past. T h i s process i n v o l v e s e x t r a p o l a t i o n o f past growth t r e n d s , modified by known or expected developments i n energy use on a r e g i o n a l , customer c l a s s , and p r o v i n c i a l b a s i s . F a c t o r s s t u d i e d i n c l u d e numbers of customers based on p o p u l a t i o n t r e n d s , changes i n per customer usage, economic t r e n d s , and known and probable i n d u s t r i a l developments. Expected changes i n the p r i c e of e l e c t r i c i t y are not e x p l i c i t y i n c l u d e d i n t h i s a n a l y s i s . The r e s u l t i n g short-term energy and peak demand f o r e c a s t s are then extended to f i v e , ten, or f i f t e e n years f o r system p l a n n i n g purposes. In i t s 1975 Report of the Task Force on Future Generation and Transmission Requirements H 9 7 5 b ) . B.C. Hydro develops two a l t e r n a t i v e econometric methodologies f o r demand f o r e c a s t i n g . In the f i r s t , the demand f o r t o t a l and e l e c t r i c energy i n B.C. i s regressed on the r e a l Gross P r o v i n c i a l Product f o r the past 20 years. The r e s u l t i n g energy-product c o e f f i c i e n t , reduced s l i g h t l y t o take account of a n t i c i p a t e d s t r u c t u r a l changes i n the B.C. economy and higher energy p r i c e s , i s then a p p l i e d t o a f o r e c a s t of r e a l G.P.P. i n order t o determine f u t u r e e l e c t r i c i t y demand. 5 The two major i n d u s t r i a l s u p p l i e r s are the Aluminum Company of Canada (Alcan) and Cominco with 18 and 9 percent, r e s p e c t i v e l y , of the p r o v i n c i a l e l e c t r i c a l energy c a p a b i l i t y . Both use hydro- e l e c t r i c sources and help supply r e g i o n a l requirements with t h e i r s u r p l u s c a p a c i t y . 9 The alternative econometric approach was performed by Dr. John Wilson (1974 ), an outside consultant. Using pooled time- series and cross-sectional data for the l a s t ten years, he regressed e l e c t r i c a l energy demand on price (both i t s own and that of substitute forms of energy) and on economic growth variables. In t h i s way, changing prices were e x p l i c i t l y considered i n demand projections. In determining i t s o f f i c i a l e l e c t r i c i t y demand forecast i n the 1975-1990 period, B.C. Hydro employed i t s conventional forecasting methodology. Total e l e c t r i c a l energy demand (including system losses and the need to supply shortages anticipated by a private e l e c t r i c a l u t i l i t y ) supplied by B.C. Hydro was expected to increase by an average annual rate of 9.3 percent over t h i s period. 6 By assuming a constant system load factor, peak demand was anticipated to r i s e at the same rate. By way of comparison, B.C. Hydro's median e l e c t r i c energy demand forecast using the adjusted energy-product c o e f f i c i e n t {which assumes population and economic growth rates eguivalent to those in the 1953-1973 period) was 8.6 percent. The Wilson study, with i t s e x p l i c i t consideration of prices, was lower s t i l l . 2.2.2 System Planning 6 B.C., Hydro's September 1976 comparable e l e c t r i c a l energy forecast (using the same 1975 base) assumes a growth rate of 7.7 percent. I s h a l l use the 1975 estimates i n t h i s study, both because I have been unable to obtain f u l l disaggregation of t h i s new estimate and because I wish to maintain consistency with other sources of information. Appendix C, however, does use t h i s updated load forecast. 10 At i t s f o r m a t i o n , B.C. Hydro's e l e c t r i c system co n t a i n e d h a l f a dozen major i s o l a t e d s e r v i c e areas s u p p l i e d by a s e r i e s of r e l a t i v e l y s m a l l g e n e r a t i n g s t a t i o n s . Since t h a t time, the t o t a l demands on the system have almost quadrupled. Strong i n t e r c o n n e c t i o n s between the p r e v i o u s l y i s o l a t e d s e c t i o n s have been forged and much l a r g e r g e n e r a t i o n p r o j e c t s have been added to the system. The one major load c e n t r e not yet connected with the main system {the P r i n c e Super t - K i t i mat-Terr ace area i n the North-west part of the province) i s now scheduled f o r i n t e g r a t i o n i n 1978. Other very s m a l l l o a d c e n t r e s s c a t t e r e d throughout the province are s u p p l i e d p r i m a r i l y by l o c a l d i e s e l generators. For the purposes of t h i s paper, we w i l l analyze o n l y the i n t e g r a t e d e l e c t r i c system s i n c e the i s o l a t e d systems, f o l l o w i n g the 1978 North-»est c o n n e c t i o n , w i l l account f o r l e s s than one percent of the f o r e c a s t e l e c t r i c a l energy demand f a c i n g B.C. Hydro. Before d e s c r i b i n g the i n t e g r a t e d system as i t now e x i s t s , i t i s important t o extend a c r i t i c a l d i s t i n c t i o n made e a r l i e r . J u s t as demand f o r e c a s t e r s are c a r e f u l to d i f f e r e n t i a t e between e l e c t r i c a l energy and peak demand reguirements, system planners t a l k i n terms of the energy c a p a b i l i t y and peaking c a p a c i t y of the system. The former r e f e r s t o the t o t a l q u a n t i t y of k i l o w a t t - hours t h a t can be produced and d e l i v e r e d by the system i n a given time p e r i o d . The l a t t e r d e s c r i b e s the maximum ra t e a t which energy can be generated and d i s t r i b u t e d and i s measured i n k i l o w a t t s . As of March 31, 1976, B.C. Hydro's i n t e g r a t e d system was s u p p l i e d by 29 h y d r o - e l e c t r i c , one c o n v e n t i o n a l thermal and 4 11 gas t u r b i n e p l a n t s accounting f o r 77, 18, and 5 p e r c e n t , r e s p e c t i v e l y , of generation peaking c a p a c i t y . Almost 50 percent of t h i s c a p a c i t y i s i n s t a l l e d i n the Shrum Generating S t a t i o n on the Peace B i v e r . . T h i s e l e c t r i c i t y i s stepped up at s u b - s t a t i o n s and t r a n s m i t t e d at 500,000 v o l t s t o the load c e n t r e s i n the p r o v i n c i a l g r i d . I t i s then stepped down at a d d i t i o n a l t r a n s f o r m a t i o n s u b - s t a t i o n s and c a r r i e d through s u b - t r a n s m i s s i o n and d i s t r i b u t i o n networks t o be d e l i v e r e d to each customer at the a p p r o p r i a t e v o l t a g e l e v e l . A B.C. Hydro map (Appendix B) o u t l i n e s the e l e c t r i c t r a n s m i s s i o n system with . e x i s t i n g f a c i l i t i e s and planned a d d i t i o n s . The e l e c t r i c a l energy demand f a c i n g B.C. Hydro v a r i e s throughout the day and year. The system's annual peak demand u s u a l l y occurs between 5:00 and 6:00 p.m. on a winter weekday. I t s minimum l e v e l , l e s s than h a l f t h a t of the peak, i s g e n e r a l l y reached before 6:00 a.m. on a h o l i d a y . To meet these v a r i a t i o n s , the A u t h o r i t y attempts to operate i t s system i n a c o s t - minimizing f a s h i o n w i t h i n the t e c h n i c a l c o n s t r a i n t s i t f a c e s . The base lo a d i s s u p p l i e d by l a r g e h y d r o - e l e c t r i c p r o j e c t s such as the Shrum p l a n t on the Peace B i v e r . As demand r i s e s , more expensive h y d r o - e l e c t r i c sources are connected. The a d d i t i o n a l U n i t s 7 to meet demand during the peak perio d are a l s o p r i m a r i l y h y d r o - e l e c t r i c although expensive gas t u r b i n e s are o c c a s i o n a l l y needed. The n a t u r a l gas (or o i l ) - f i r e d Burrard thermal p l a n t i s g e n e r a l l y used i n the winter and s p r i n g to make up a n t i c i p a t e d s h o r t f a l l s between t o t a l e l e c t r i c a l energy demand and t h a t which 7 U n i t s i n generating p l a n t s w i l l be c a p i t a l i z e d throughout t h i s paper to d i s t i n g u i s h them from the more gen e r a l use of the term. 12 can be s u p p l i e d by h y d r o - e l e c t r i c sources, although i t too sometimes performs a peaking r o l e . 8 The extent to which the f o s s i l f u e l f i r e d p l a n t s are used depends l a r g e l y upon water c o n d i t i o n s . In the 1975-76 f i s c a l year, o n l y about t e n percent of the energy generated came from thermal s o u r c e s . Within the l a s t year, new h y d r o - e l e c t r i c p l a n t s have been brought i n t o s e r v i c e on the Kootenay and Columbia R i v e r s . C o n s t r u c t i o n i s well underway on both the Peace and Pend d * O r e i l l e R i v e r s with the new power expected by 1980. In determining f u t u r e expansion reguirments, B.C. Hydro looks at both the energy and peak demands i t a n t i c i p a t e s having to supply. Most of the p r o j e c t s i t c o n s i d e r s would add to both energy c a p a b i l i t y and peak c a p a c i t y . Some, however, would produce only a d d i t i o n a l e l e c t r i c a l energy while others add o n l y to peaking c a p a c i t y . In the p e r i o d to 1990, the major new p r o j e c t s p r o v i d i n g both energy and c a p a c i t y being s e r i o u s l y contemplated are hydro- e l e c t r i c p l a n t s on the Peace and Columbia R i v e r s and c o a l - f i r e d s t a t i o n s i n the Hat Creek and East Kootenay Regions. D i v e r s i o n s of r i v e r s through e x i s t i n g f a c i l i t i e s on the Peace and Columbia R i v e r s are the energy-only p r o j e c t s being c o n s i d e r e d . I n s t a l l a t i o n of new t u r b i n e s and g e n e r a t o r s at e x i s t i n g or planned h y d r o - e l e c t r i c s i t e s r e p r e s e n t the main c a p a c i t y - o n l y p r o j e c t s p o s s i b l e . In a d d i t i o n , two gas t u r b i n e U n i t s are contemplated f o r Vancouver I s l a n d t o meet p o s s i b l e l o c a l s Recent f e d e r a l c o n t r o l s have r e g u i r e d t h a t any e l e c t r i c i t y exports generated at Burrard be p r i c e d at g r e a t e r than the e q u i v a l e n t gas export p r i c e . T h i s has reduced exports somewhat, although t h i s high p r i c e serves as l i t t l e d e t e r r e n t during very dry p e r i o d s i n the U.S. P a c i f i c Northwest. 13 shortages pending completion o f new underwater t r a n s m i s s i o n c a p a c i t y from the mainland. Beyond 1990, n u c l e a r power, more d i s t a n t and/or expensive h y d r o - e l e c t r i c s i t e s and l e s s a c c e s s i b l e c o a l d e p o s i t s are being c o n s i d e r e d as p o s s i b l e g e n e r a t i o n sources. In s e l e c t i n g these p r o j e c t s from a l a r g e r group of p o t e n t i a l e l e c t r i c i t y s o u r c e s , B.C. Hydro takes e x p l i c i t account of the e a r l i e s t p o s s i b l e i n - s e r v i c e dates and the expected c a p i t a l and o p e r a t i n g c o s t s t o the A u t h o r i t y a s s o c i a t e d with them. The comparative c o s t s of each of these p r o j e c t s ( i n c l u d i n g the a s s o c i a t e d t r a n s m i s s i o n costs) over t h e i r l i f e t i m e i s c a l c u l a t e d , u s i n g v a r i o u s d i s c o u n t r a t e s . The r e s u l t a n t l e a s t - c o s t rankings are then adjusted a c c o r d i n g t o l e g a l , environmental or s o c i a l c o n s i d e r a t i o n s not a l r e a d y i n c l u d e d . 9 These t e n t a t i v e p r o j e c t c h o i c e s are then used to develop a l t e r n a t i v e g e n e r a t i o n and t r a n s m i s s i o n programmes r e q u i r e d to meet the t e c h n i c a l c r i t e r i a e s t a b l i s h e d f o r energy and peak l o a d requirements over the f o r e c a s t p e r i o d . These programmes are subsequently analyzed with r e f e r e n c e t o economic c r i t e r i a to e s t a b l i s h the o p t i m a l plan. The t e c h n i c a l c r i t e r i o n i n e f f e c t f o r determining energy c a p a b i l i t y i s t h a t the f i r m c a p a b i l i t y of the system be equal to or g r e a t e r than the f o r e c a s t e l e c t r i c energy demand. Firm energy * Although not yet p a r t o f i t s formal decision-making process, B.C. Hydro has r e c e n t l y completed a d e t a i l e d b e n e f i t - c o s t a n a l y s i s employing economic p r i n c i p l e s . T h i s study (1976c) attempts to help choose between d i f f e r e n t g e n e r a t i o n p r o j e c t s by e x p l i c i t l y c o n s i d e r i n g both the q u a n t i f i a b l e and non- g u a n t i f i a b l e r e g i o n a l and environmental impacts i n a d d i t i o n to the t r a d i t i o n a l d i r e c t c o s t s and b e n e f i t s o f the a l t e r n a t i v e p r o j e c t s . 14 c a p a b i l i t y i s e s s e n t i a l l y the t o t a l energy production p o s s i b l e from hydro p l a n t s d u r i n g c r i t i c a l water c o n d i t i o n s (the lowest f i v e years of recorded stream flows) plus thermal p l a n t s operated at t h e i r maximum annual energy c a p a b i l i t y plus power purchases made i n accordance with f i r m c o n t r a c t s . To the extent that a c t u a l water c o n d i t i o n s exceed the c r i t i c a l standard (average c o n d i t i o n s i n c r e a s e energy c a p a b i l i t y some 5 to 10 p e r c e n t ) , thermal g e n e r a t i o n i s cut back to reduce o p e r a t i n g c o s t s . The t e c h n i c a l c r i t e r i o n now adopted f o r determining peak c a p a c i t y reguirements i s the l o s s - o f - l o a d p r o b a b i l i t y method. The essence of t h i s approach i s t h a t excess peak c a p a c i t y i s b u i l t to the p o i n t where the probable occurrence of system peak demand exceeding system peak c a p a c i t y i s one day i n ten y e a r s . This r e c e n t l y adopted c r i t e r i o n r e p l a c e s one which had suggested r e l a t i v e l y more re s e r v e c a p a c i t y i n the 1970's and r e l a t i v e l y l e s s i n the 1980's. I t i s the standard r e g u i r e d o f a l l 18 members i n the Northwest Power P o o l . Having determined that the a l t e r n a t i v e programmes meet these two t e c h n i c a l c r i t e r i a , B.C. Hydro then compares them on the b a s i s of discounted cash flow a n a l y s i s , using nominal expenditures and d i s c o u n t r a t e s . The cash stream i n c l u d e s o r i g i n a l c a p i t a l e x penditures, o p e r a t i n g expenses and, at l e a s t t h e o r e t i c a l l y , the c o s t of p l a n t replacement and subsequent o p e r a t i o n a t i n t e r v a l s equal to i t s estimated u s e f u l l i f e . E s s e n t i a l l y , the programme with the h i g h e s t i n t e r n a l r a t e of r e t u r n (and a l s o above the minimum accept a b l e nominal r a t e of 15 percent) i s chosen as the most economic. 15 As a r e s u l t of t h i s a n a l y s i s , the Task Force recommended a generation and t r a n s m i s s i o n p l a n through to 1990. The major combined energy and c a p a c i t y p r o j e c t s , with t h e i r suggested i n - s e r v i c e dates, were as f o l l o w s ; Revelstoke, on the Columbia B i v e r (1981), Hat Creek c o a l p l a n t Stage 1 (1983), Stage 2 (1986), and East Kootenay c o a l p l a n t (1989). The energy-only d i v e r s i o n p r o j e c t s were recommended as soon as l e g a l l y and/or env i r o n m e n t a l l y f e a s i b l e : Kootenay R i v e r D i v e r s i o n to the Columbia R i v e r (1984) and McGregor River D i v e r s i o n to the Peace Bi v e r (1985). The c a p a c i t y - o n l y a d d i t i o n s of t u r b i n e s and generators a t e x i s t i n g or planned h y d r o - e l e c t r i c s i t e s were to begin i n 1985 and average one a year to 1990. Major new t r a n s m i s s i o n p r o j e c t s were a s s o c i a t e d e i t h e r with t r a n s p o r t i n g e l e c t r i c i t y from the new combined energy and c a p a c i t y p r o j e c t s or with more s t r o n g l y i n t e g r a t i n g the system and meeting growth i n v a r i o u s l o a d c e n t r e s . B.C. Hydro has not as comprehensively analyzed the need to expand s u b - t r a n s m i s s i o n , t r a n s f o r m a t i o n and d i s t r i b u t i o n f a c i l i t i e s . T h i s i s undoubtedly due t o the dominant r o l e played by the g e n e r a t i o n and t r a n s m i s s i o n programme which the a u t h o r i t y expects, i n the 1977-1981 p e r i o d , to r e q u i r e 51 and 19 percent r e s p e c t i v e l y , of the e l e c t r i c s e r v i c e ' s c a p i t a l budget. I t appears, however, t h a t as one moves f u r t h e r from the g e n e r a t i o n l e v e l , c a p i t a l c o s t s become i n c r e a s i n g l y r e l a t e d to peak c a p a c i t y c o n s i d e r a t i o n s and to the c h a r a c t e r i s t i c s of i n d i v i d u a l customers. Forecasted energy c a p a b i l i t y shortages are c l e a r l y d r i v i n g the expansion of the generation programme u n t i l the l a t t e r p a r t 16 of the 1980 ,s.*o Hydro fs e x p l a n a t i o n f o r t h i s i s t h a t f o r hydro- e l e c t r i c sources, generating c a p a c i t y i s sometimes i n s t a l l e d s p e c i f i c a l l y f o r the purpose of a s s u r i n g the f u l l u t i l i z a t i o n of a v a i l a b l e h y d r a u l i c energy under v a r y i n g stream flow c o n d i t i o n s , thus r e s u l t i n g i n excess peaking c a p a c i t y . T h i s s u r p l u s i s expected to disappear as thermal energy sources begin t o play a more important r o l e i n the system. 2.2.3 F i n a n c i n g At i t s formation, B.C. Hydro ac q u i r e d a l l the out s t a n d i n g debt of the two o r g a n i z a t i o n s from which i t sprang, and compensated the e q u i t y owners of the p r i v a t e c o r p o r a t i o n . I t s subsequent expansion has been f i n a n c e d very l a r q e l y by debt instruments, with i n t e r n a l l y generated funds p r o v i d i n g most of the balance. P r o v i n c i a l government grants, i n the form of r u r a l e l e c t r i f i c a t i o n a s s i s t a n c e and t r a n s i t o p e r a t i o n s u b s i d i e s , and c a p i t a l c o n t r i b u t i o n s from some customers have provided r e l a t i v e l y minor a d d i t i o n a l amounts. Funds r e c e i v e d as a r e s u l t of the Columbia Hiver Treaty have paid f o r most of the three storage dams, with the d e f i c i t to be charged to the e l e c t r i c s e r v i c e . A f t e r n e t t i n g out the Treaty dams, t h i s s e r v i c e accounts f o r approximately 90 percent of B.C. Hydro's net property i n s e r v i c e . The A u t h o r i t y ' s o u t s t a n d i n g debt i n the form of bonds has r i s e n from .8 to 4.0 b i l l i o n d o l l a r s between 1963 and 1976. A l a r g e share of t h i s i s he l d i n p r o v i n c i a l government t r u s t funds 1 0 The system i s de s c r i b e d as being ' e n e r g y - c r i t i c a l * (as d i s t i n c t from ' c a p a c i t y - c r i t i c a l ' ) under these circumstances. 17 and the Canadian Pension Plan Investment Fund, although B.C. Hydro i s being f o r c e d to r e l y i n c r e a s i n g l y on both p r i v a t e placement and p u b l i c i s s u e s i n Canada and the United S t a t e s . The i n t e r e s t r a t e on t h i s e x i s t i n g debt ranges from 3 1/4 to 10 1/2 percent with an embedded average of 7.4 percent i n 1976. The average e f f e c t i v e annual i n t e r e s t c o s t of new i s s u e s d u r i n g the 1975-76 f i s c a l year exceeded 10 percent f o r the f i r s t time. As e s t a b l i s h e d under i t s 1964 A c t , a l l e x i s t i n g s e c u r i t i e s of the A u t h o r i t y are backed by the Province and s i n k i n g funds are provided f o r the r e t i r e m e n t o f long term debt. At present, B.C. Hydro's share of net o u t s t a n d i n g debt guaranteed by the Province of B r i t i s h Columbia stands at 69 p e r c e n t . 1 1 Each year's new i s s u e s must be approved by the L e g i s l a t u r e through an amendment to the borrowing c e i l i n g set i n the 1964 A c t . The s i n k i n g fund payments on debt i s s u e d w i t h i n the l a s t f i v e years are designed t o approximately f u l l y refund the p r i n c i p a l . However, much of the debt a c q u i r e d or i s s u e d by Hydro i s l i n k e d to payments which w i l l cover l e s s than h a l f the amount due a t maturity. B.C. Hydro's net income has f a l l e n i n recent years to the p o i n t where only a s p e c i a l p r o v i n c i a l subsidy l a s t year prevented a l o s s . As a r e s u l t , i n t e r n a l l y generated funds have been p r o v i d i n g an i n c r e a s i n g l y s m a l l e r percentage of the A u t h o r i t y ' s c a p i t a l requirements. In the 1975-76 f i s c a l year, 1 1 The other Crown c o r p o r a t i o n s with net o u t s t a n d i n g debt guaranteed by the P r o v i n c e , with t h e i r share of the t o t a l i n brackets, a r e : B.C. Railway Company (12), B.C. School D i s t r i c t s C a p i t a l F i n a n c i n g A u t h o r i t y (12), B.C. Regional H o s p i t a l D i s t r i c t s F i n a n c i n g A u t h o r i t y (4). The p r o v i n c i a l government i t s e l f has no net outstanding d i r e c t debt. 18 only 10 percent of these requirements were met from i n t e r n a l sources, even a f t e r the s p e c i a l s u b s i d y . T h i s i s r e f l e c t e d i n the f a c t t h a t the r a t i o of debt to r e t a i n e d e a r n i n g s i s now 95:5. In an attempt t o improve i t s c r e d i t - w o r t h i n e s s , B.C. Hydro has embarked on a programme t o i n c r e a s e s u b s t a n t i a l l y i t s net income to the p o i n t where i t w i l l approximate o n e - t h i r d of i t s net i n t e r e s t o b l i g a t i o n s . The process of f o r e c a s t i n g cash requirements i s b a s i c a l l y one of t a k i n g the c a p i t a l expenditure f i g u r e s provided by the system planners and a d j u s t i n g them to i n c l u d e net f i n a n c i a l o b l i g a t i o n s . In the next f i v e y e a r s , f o r example, B.C. Hydro estimates c a p i t a l expenditures on i t s system of 5.0 b i l l i o n nominal d o l l a r s (93 percent of which w i l l be i n the e l e c t r i c s e r v i c e ) p l u s .3 b i l l i o n nominal d o l l a r s t o meet long-term debt m a t u r i t i e s and s i n k i n g fund reguirements. I t a n t i c i p a t e s t h a t between 14 and 23 percent (depending upon the degree of passenger t r a n s p o r t a t i o n s e r v i c e s s u b s i d i e s ) w i l l be generated i n t e r n a l l y . The balance would be r a i s e d i n the bond market. 2.2.4 Rate S e t t i n g B.C. Hydro does not appear t o have been given any f o r m a l d i r e c t i o n on the q u e s t i o n of the l e v e l or s t r u c t u r e o f i t s r a t e s . The Power l e t , a p p l y i n g to the former B r i t i s h Columbia Power Commission, e x p l i c i t l y s t a t e d t h a t "the Commission's r a t e schedules s h a l l be designed to permit and encourage the maximum use of power" ( B r i t i s h Columbia L e g i s l a t u r e , 1960). The subsequent B r i t i s h Columbia Hydro and Power A u t h o r i t y Act remained s i l e n t on t h i s i s s u e . 19 In i t s f i r s t year, B.C. Hydro introduced two r a t e r e d u c t i o n s and sta n d a r d i z e d both r e s i d e n t i a l and s m a l l commercial e l e c t r i c r a t e s throughout the province. A bulk power r a t e was i n t r o d u c e d f o r l a r g e i n d u s t r i e s , r e s u l t i n g i n t h e a d d i t i o n o f s i g n i f i c a n t l o a d s t o the system. A new uniform extension p o l i c y a p p l i c a b l e to a l l r e s i d e n t i a l and farm e l e c t r i c customers was i n i t i a t e d i n which B.C. Hydro p a i d a gr e a t e r p r o p o r t i o n of the i n i t i a l c o s t s o f e x t e n s i o n s . In the words of the 1963 Annual Report, "the adoption of new exte n s i o n p o l i c i e s and the i n t r o d u c t i o n of lower power r a t e s are designed to encourage the development and expansion of i n d u s t r y i n B r i t i s h Columbia" (B.C. Hydro, 1963,6) . E l e c t r i c r a t e s continued to f a l l i n each of the next three years. Two a l l - e l e c t r i c r a t e s were introduced t o encourage the use of e l e c t r i c i t y f o r he a t i n g homes and sm a l l commercial premises. U n l i m i t e d "one-cent power" became a v a i l a b l e t o a l l r e s i d e n t i a l customers i n 1965 and was designed to "encourage home owners t o make gr e a t e r use of e l e c t r i c a p p l i c a n c e s , a i r c o n d i t i o n i n g , d e c o r a t i v e l i g h t i n g and e l e c t r i c h e a t i n g " . (B.C. Hydro, 1965,6) In 1967 e l e c t r i c r a t e s were r a i s e d , a move repeated i n 1970, 1974, 1975, and 1976. Most of these i n c r e a s e s ranged between 10 and 20 percent although the l a r g e users were h i t with hikes of more than 50 percent between 1974 and 1976. The 1974 Annual Report i n d i c a t e d t h a t s a l e s promotion a c t i v i t y had been re p l a c e d with programmes designed to promote the wise and e f f i c i e n t use of energy. There are now e s s e n t i a l l y t h r e e b a s i c customer r a t e 20 c l a s s e s : r e s i d e n t i a l , g e n e r a l and bulk, although a v a r i e t y of other r a t e c l a s s e s do e x i s t , t h e i r s a l e s volume i s r e l a t i v e l y s m a l l and they are o f t e n c l o s e d to new u s e r s . In 1976, the standard r e s i d e n t i a l r a t e was based on a simple two hlock d e c l i n i n g energy charge. The f i r s t 550 k i l o w a t t - h o u r s (KWH) per two month p e r i o d were b i l l e d at 4.6 c e n t s (46 m i l l s ) each with a l l a d d i t i o n a l at 1.7 cents each. The minimum charge f o r the p e r i o d was $6.14, e q u i v a l e n t to 133 KIH a t the higher p r i c e , approximately e i g h t y percent of a l l users i n the c l a s s reached the second block. Average energy use during t h i s two month period was 1400 KWH, y i e l d i n g a r e s i d e n t i a l average p r i c e of 2.8 cents per KHH. The general s e r v i c e c l a s s has two s e c t i o n s , depending upon the customer's peak monthly demand. For more than 90 percent of the customers i n t h i s c l a s s , peak demand i s below a l e v e l c o n s i d e r e d economic f o r the i n s t a l l a t i o n of a meter s e p a r a t e l y measuring energy and peak demand. In 1976, these customers were b i l l e d on the b a s i s of an energy charge c o n s i s t i n g of f o u r d e c l i n i n g blocks ( s t a r t i n g at 5.35 cents and f a l l i n g t o 1.5 cents per KWH) and a f i x e d minimum charge of $8.50 f o r two months. The average p r i c e f o r t h i s group was g e n e r a l l y higher than what i t would have been f o r the same consumption under the r e s i d e n t i a l r a t e s t r u c t u r e . The vast m a j o r i t y of commercial customers f a l l w i t h i n t h i s group. For the customers with a l a r g e r peak demand, e s s e n t i a l l y the l a r g e commercial and s m a l l e r i n d u s t r i a l consumers using over 70 percent of the energy consumed by the g e n e r a l c l a s s , a two part t a r i f f i s i n e f f e c t . In 1976, peak demand f o r the month was 21 b i l l e d on an i n c r e a s i n g f o u r part b l ock r a t e . T o t a l energy demand i n t h i s p e r i o d faced a d e c l i n i n g s i x p a r t energy charge. The net e f f e c t of these two opposing movements, given a f i x e d load f a c t o r , was f o r the p r i c e per KWH to g e n e r a l l y f a l l with i n c r e a s e d consumption. Average p r i c e per KWH f o r t h i s group was g e n e r a l l y below that f o r e i t h e r the r e s i d e n t i a l or commercial customers. The minimum monthly charge was the g r e a t e r of a f i x e d amount or 75 percent of the peak demand durin g the winter months. The t h i r d c l a s s , bulk customers, have g e n e r a l l y been the l a r g e s t group i n terms of annual energy s a l e s . Taking power a t l e v e l s of at l e a s t 60,000 v o l t s , they comprise l a r g e i n d u s t r i a l concerns such as pulp and paper m i l l s , e l e c t r o - c h e m i c a l p l a n t s , o i l r e f i n e r i e s and mines. They r e q u i r e e i t h e r one or two year's n o t i c e of a change i n r a t e s and faced average i n c r e a s e s r a n g i n g from 55 to 70 percent between 197 4 and 1976. Rate i n c r e a s e s f o r the next two years approximating 10 percent annually have been announced f o r these customers., The peak demand charge f o r bulk customers i s at a f l a t r a t e and c u r r e n t l y comprises some two-thirds of the average customer's t o t a l b i l l . Peak demand c a l c u l a t i o n s use the " r a t c h e t " p r i n c i p l e i n t h a t they are based on the g r e a t e r o f that month's peak demand and 75 percent of the highest peak demand i n any of the eleven preceding months. In 1976, a l l energy was s o l d at .3 cents per KWH. Monthly minimum charges were based on the peak demand as determined above, while the annual minimum charge was based on peak demand " r a t c h e t e d " only to the winter months. The average p r i c e o f e l e c t r i c i t y f o r t h i s 22 customer c l a s s approximated one cent per KWH. Other s m a l l e r r a t e c l a s s e s which we s h a l l not d e a l with i n t h i s study cover i r r i g a t i o n , s t r e e t l i g h t i n g , rooming houses and areas with s p e c i a l r a t e s and those served by d i e s e l g e n e r a t o r s . B.C. Hydro does not now o f f e r any i n t e r r u p t i b l e s e r v i c e , with reduced r a t e s , f o r i t s l a r g e i n d u s t r i a l customers. In determining r a t e l e v e l s and s t r u c t u r e s , B.C. Hydro has assumed the f o l l o w i n g power p r i c i n g g o a l : To s e l l power to customers at r a t e s based on c o s t s of s e r v i c e ; such c o s t s to i n c l u d e a l l c o s t s r e g u i r e d to meet s t a t u t o r y o b l i g a t i o n s and Government p o l i c y d i r e c t i o n s and t o ensure the continuance o f B.C. Hydro as a f i n a n c i a l l y independent and v i a b l e c o r p o r a t e e n t i t y . (B. C. Hydro, 1975b,16) The A u t h o r i t y reviews r a t e s f o r i t s e l e c t r i c and gas s e r v i c e s annually i n the l i g h t of i t s p r o j e c t i o n s of o p e r a t i n g r e s u l t s and reguirements f o r c a p i t a l expenditures. Rate l e v e l s a r e s e t for these s e r v i c e s p r i o r to the commencement of a f i s c a l year to ensure that l o s s e s w i l l not be i n c u r r e d i n that f i s c a l year. The d e s i r e d s u r p l u s or p r o f i t f o r the f o r e c a s t year depends on the extent to which i n t e r n a l l y generated funds are t o f i n a n c e f u t u r e expansion, and i s now s l a t e d to reach 30 percent of net i n t e r e s t payments w i t h i n s i x to e i g h t years. The A u t h o r i t y ' s most rec e n t Statement of Income, from which annual net income i s determined, i s c o ntained i n Appendix A. Standard h i s t o r i c a l c o s t accounting procedures are f o l l o w e d , with d e p r e c i a t i o n being c a l c u l a t e d on a s t r a i g h t l i n e b a s i s and gross i n t e r e s t on debt being reduced by i n t e r e s t during c o n s t r u c t i o n and income from s i n k i n g fund investments. S a l a r i e s and net i n t e r e s t on debt each account f o r 23 approximately 30 percent of expenses, f o l l o w e d by m a t e r i a l s and s e r v i c e s , d e p r e c i a t i o n and ta x e s . These c o s t s are q u i t e f i n e l y disaggregated w i t h i n B.C. Hydro. Operating and c a p i t a l c o s t s are assigned to the v a r i o u s f u n c t i o n s w i t h i n each s e r v i c e . For the e l e c t r i c s e r v i c e , these c o s t s are a l l o c a t e d between the c a p a c i t y and energy components. F i n a l l y , each c l a s s o f customers i s given i t s share of these c o s t s . Bate l e v e l s f o r each c l a s s are designed to cover completely the p r o j e c t e d " c o s t o f s e r v i c e " based on t h i s " f u l l y d i s t r i b u t e d " average h i s t o r i c a l c o s t accounting method, plus a share o f the d e s i r e d annual s u r p l u s . The methodology employed t o a l l o c a t e c o s t s between the energy and c a p a c i t y components i s of fundamental importance. At present, a l l c o s t s a s s o c i a t e d with t r a n s m i s s i o n , t r a n s f o r m a t i o n and d i s t r i b u t i o n as w e l l as the c a p i t a l c o s t s o f the generating equipment ( t u r b i n e s , generators, etc.) are c a t e g o r i z e d as c a p a c i t y . The gen e r a t i o n c o s t s not a s s o c i a t e d with g e n e r a t i n g equipment, such as the dam, are a l l o c a t e d between energy and c a p a c i t y based on p l a n t f a c t o r , the r a t i o of the average load on the p l a n t to i t s c a p a c i t y . Thus a r e s e r v o i r which i s used t o supply base-load energy has much of i t s c o s t a l l o c a t e d t o the energy component, u n l i k e a peaking p l a n t . Some o p e r a t i n g c o s t s at the generation l e v e l , such as f u e l and a share of labour and water l i c e n c e f e e s , are a l s o c l a s s e d as e n e r g y - r e l a t e d . The r e s u l t of t h i s approach i s t h a t the great m a j o r i t y o f c o s t s i n the e l e c t r i c s e r v i c e are a t t r i b u t e d t o c a p a c i t y , h e l p i n g to reduce the share o f c o s t s borne by the high l o a d f a c t o r customer c l a s s e s . H i s t o r i c a l l y , the commercial customers 24 have g e n e r a l l y borne somewhat more, and the r e s i d e n t i a l customers somewhat l e s s of t h e i r share of c o s t s based on t h i s a l l o c a t i o n procedure. The a c t u a l design of the r a t e s t r u c t u r e t o recover the above c o s t s f o r each customer c l a s s does not appear to be as c l e a r l y a d e f i n e d process. C o n s i d e r a t i o n s of revenue s t a b i l i t y , f u t u r e c o s t s t r u c t u r e s , p e r m i s s i b l e r a t e of change and p o l i t i c a l impact a l l weigh h e a v i l y on the r a t e maker's mind i n a d d i t i o n to the " c o s t of s e r v i c e " i n f o r m a t i o n . Bulk r a t e customers, with t h e i r separate f l a t charges f o r energy and peak demand, f a c e an energy charge twice that c a l c u l a t e d under the " c o s t of s e r v i c e " method, with a corresponding r e d u c t i o n i n the peak demand charge. T h i s adjustment would appear to r e s u l t from an uneasiness about the extreme imbalance between these two components under t h i s a l l o c a t i o n scheme. Smaller i n d u s t r i a l customers seem to have t h e i r energy and c a p a c i t y charges designed t o approach those of the bulk users as t h e i r consumption i n c r e a s e s , although the marginal energy charqe i n 1976 never f e l l below almost twice t h a t of the l a r g e u s e r s . For the r e s i d e n t i a l and commercial customers, with t h e i r d e c l i n i n g block r a t e energy charges, much of the c a p a c i t y or f i x e d c o s t s are placed on the i n i t i a l b l o c k and minimum charge, with t a i l i n g b l o c k s r e f l e c t i n g an i n c r e a s e d share of the energy c o s t s . The 1977 r a t e h i k e s seem t o i n d i c a t e an i n c r e a s e d emphasis on the energy component o f the b i l l . Thus bulk users w i l l see t h e i r energy charge double to .6 cents i n 2 y e a r s , while t h e i r peak demand charge i n c r e a s e s only m a r g i n a l l y . R e s i d e n t i a l users face an i n c r e a s e d t a i l i n g block of 2.0 cents per KWH although a 25 new s e r v i c e charge of $ 3 . 0 0 each two-month p e r i o d w i l l have the b i g g e s t impact on s m a l l users. The only r a t e r e s t r u c t u r i n g evident i n the i n c r e a s e f o r the g e n e r a l s e r v i c e c l a s s i s the i n t r o d u c t i o n of a monthly s e r v i c e charge of $ 2 . 2 5 , again r a i s i n g c o s t s r e l a t i v e l y more f o r the s m a l l e r accounts. These r a t e s t r u c t u r e changes r e f l e c t B.C. Hydro's longer term i n t e n t i o n of " f l a t t e n i n g " the r a t e s f o r energy consumption while r a i s i n g the i n i t i a l charge designed t o cover f i x e d expenses. In a r e c e n t statement, the Chairman of B.C. Hydro claimed t h a t " e l e c t r i c a l r a t e s should be n e u t r a l i n t h e i r e f f e c t upon use with s e r v i c e charges completely separate and a f l a t r a t e f o r energy used as the second component of the customer's b i l l " (Bonner, 1 9 7 7 ) . He went on to say t h a t , i f f u l l y implemented, t h i s would i n v o l v e a s e r v i c e c o s t component ( f o r r e s i d e n t i a l customers) of about $ 8 . 6 5 per month to which an energy charge would have to be a d d e d . 1 2 Because of the burden t h i s would place on the s m a l l user, he s t a t e d t h a t t h i s " i d e a l n e u t r a l r a t e " would probably never be achieved, but t h a t f u t u r e adjustments would aim at f u r t h e r r a t e n e u t r a l i t y as between i n c e n t i v e and d i s i n c e n t i v e to use. , 2 . 3 Summary Th i s chapter has attempted to present the necessary background on B.C. Hydro to proceed with an economic a n a l y s i s of the d e t e r m i n a t i o n and i m p l i c a t i o n s of an a p p r o p r i a t e r a t e * 2 I f the revenue reguirement f o r the r e s i d e n t i a l c l a s s were t o be met, t h i s would imply a f l a t energy charge o f 1 .0 cents per KWH based on 1976 f i g u r e s . , 26 s t r u c t u r e f o r t h e A u t h o r i t y . I t has d i s c u s s e d the i n s t i t u t i o n a l framework w i t h i n which B.C. Hydro operates and has focu s s e d on the A u t h o r i t y ' s past and present p o l i c i e s i n key areas of the e l e c t r i c s e r v i c e . The essence of the e l e c t r i c a l planning process a t B.C. Hydro i s as f o l l o w s . The demand f o r e c a s t i n g s e c t i o n produces a 10 t o 15 year f o r e c a s t o f expected energy and peak demand t o be met by the A u t h o r i t y . The system planning group designs a l e a s t - cost expansion and o p e r a t i n g plan s u h j e c t to c e r t a i n t e c h n i c a l , l e g a l and environmental c o n s t r a i n t s to meet t h i s f o r e c a s t demand. The f i n a n c i a l team i s advised of the c a p i t a l reguirements t h i s w i l l e n t a i l and c a l c u l a t e s how best to r a i s e the necessary funds. F i n a l l y , the r a t e s department p r o j e c t s the necessary r a t e l e v e l s and s t r u c t u r e f o r each c l a s s of customers i n an attempt to meet f a i r l y the revenue reguirements of the A u t h o r i t y . The l i n k a g e between each of these f u n c t i o n s i s e x p l i c i t . The connection between the r a t e s t r u c t u r e and demand f o r e c a s t i n g i s not. 27 3.. THEORY AND METHODOLOGY OF MARGINAL COST PRICING 3.1 Emergence Of The Theory Of M. C.P. Economic theory suggests t h a t a p r o f i t maximizing monopolist would tend to produce l e s s , and charge more, than would be s o c i a l l y o p t i m a l . Aggregate p r o d u c t i o n would be determined by s e t t i n g marginal c o s t e q u a l t o marginal revenue, with s e l l i n g p r i c e being a f u n c t i o n of the demand f o r the product. I f the product's aggregate market c o u l d be d i v i d e d i n t o submarkets with d i f f e r e n t p r i c e e l a s t i c i t i e s , then p r i c e d i s c r i m i n a t i o n would be attempted whereby those s e c t o r s with the most i n e l a s t i c demand were charged the h i g h e s t p r i c e . In a d d i t i o n , where p o s s i b l e , r a t e s t r u c t u r e s w i t h i n each submarket would be designed with marginal p r i c e below average p r i c e so that the monopolist c o u l d capture some of the consumer s u r p l u s a s s o c i a t e d with downward s l o p i n g demand curves. Because of the economies of s c a l e inherent i n t h e i r c a p i t a l - i n t e n s i v e p r o d u c t i o n processes, most p u b l i c u t i l i t i e s were co n s i d e r e d to be s o - c a l l e d " n a t u r a l monopolies". E l e c t r i c u t i l i t i e s were assured of t h i s monopoly p o s i t i o n , but were c a r e f u l l y watched to ensure t h a t they d i d not make unwarranted p r o f i t s . The primary focus of r a t e s e t t i n g became t o ensure t h a t the r e s u l t i n g t o t a l revenues were adequate but not e x c e s s i v e . In the case of privately-owned e l e c t r i c u t i l i t i e s , t h i s adequacy was o f t e n determined throuqh formal r e g u l a t i o n based on an 28 approved r a t e of r e t u r n on an h i s t o r i c a l c ost r a t e b a s e . 1 3 For p u b l i c a l l y - o w n e d or Crown c o r p o r a t i o n s , the process was u s u a l l y l e s s formal and i n v o l v e d ensuring t h a t net accounting income was approximately e g u a l to t h a t r e g u i r e d to assure the long term f i n a n c i a l v i a b i l i t y o f the u t i l i t y . In d e s i g n i n g r a t e s t r u c t u r e s c o n s i s t e n t with t h i s t o t a l revenue o b j e c t i v e , p r a c t i t i o n e r s g e n e r a l l y b e l i e v e d t h a t p r i c e s should l i e somewhere between the "incremental c o s t " and the "value of s e r v i c e " of the i n c r e m e n t a l l o a d . 1 * Although never very c l e a r l y d e f i n e d , " i n c r e m e n t a l c o s t s " were g e n e r a l l y h e l d to be below average c o s t s i n both the s h o r t and long run, thus su g g e s t i n g a d e c l i n i n g block r a t e s t r u c t u r e w i t h i n each customer c l a s s . The "value of s e r v i c e " concept, intended t o set an upper l i m i t on p r i c e , was e s s e n t i a l l y an i n v e r s e measure o f the e l a s t i c i t y of demand f o r e l e c t r i c i t y . The l a r g e i n d u s t r i a l users, f o r example, with a l t e r n a t i v e sources of energy a v a i l a b l e to them, were s a i d t o have a low "value of s e r v i c e " . Thus p r i c e d i s c r i m i n a t i o n between c l a s s e s u s u a l l y l e d to lower p r i c e s f o r higher use customer c l a s s e s . The combined r e s u l t was g e n e r a l l y a d e c l i n i n g average p r i c e f o r e l e c t r i c i t y as consumption i n c r e a s e d , both w i t h i n and between customer c l a s s e s . The expanded use that such r a t e s t r u c t u r e s encouraged was designed to b e n e f i t a l l by l e a d i n g to lower average c o s t s , and hence p r i c e s , i n the f u t u r e . 1 3 C o n s i d e r a b l e d i s c u s s i o n i n t h e economic l i t e r a t u r e has centred around the q u e s t i o n of the p o s s i b l e d i s t o r t i o n s i n the r e l a t i v e i n t e n s i t y of use of v a r i o u s f a c t o r s of. p r o d u c t i o n r e s u l t i n g from the r e g u l a t o r y method. See H e l l i w e l l (1977) and C a l l e n (1976). 1 4 See, f o r example, the p r a c t i c a l guide to the a r t of e l e c t r i c r a t e making by Caywood (1956). 29 Micro-economic t h e o r y t e l l s us t h a t a necessary c o n d i t i o n f o r the maximization of s o c i e t y ' s welfare i s that the marginal s o c i a l b e n e f i t from the p r o d u c t i o n of an a d d i t i o n a l u n i t of a product i s egual to the marginal s o c i a l c o s t r e s u l t i n g from t h a t production. I f i t i s assumed t h a t an i n d i v i d u a l ' s demand curve r e p r e s e n t s marginal s o c i a l b e n e f i t and t h a t marginal s o c i a l and p r i v a t e c o s t s are e q u a l , then t h i s c o n d i t i o n f o r economic e f f i c i e n c y i m p l i e s that the marginal p r i c e of a product should egual i t s marginal cost of p r o d u c t i o n . 1 5 In t h i s way, a consumer w i l l be a b l e t o a d j u s t h i s consumption p a t t e r n i n response t o r e l a t i v e p r i c e s so as to maximize h i s own s a t i s f a c t i o n while a t the same time ensure t h a t s o c i e t y ' s s c a r c e resources are being used most e f f i c i e n t l y . N a t u r a l economic f o r c e s w i l l a c t to s a t i s f y t h i s c o n d i t i o n i n a p e r f e c t l y c o m p e t i t i v e market s i t u a t i o n , but w i l l be l a c k i n g i n the presence o f a monopoly. I f , i n f a c t , e x t e r n a l i t i e s do e x i s t on e i t h e r the demand or supply s i d e of the f o r m u l a t i o n , then we must r e s o r t to the o r i g i n a l c o n d i t i o n s f o r economic e f f i c i e n c y employing marginal s o c i a l c o s t s and b e n e f i t s . The presence o f a t e c h n i c a l e x t e r n a l i t y i n the e l e c t r i c u t i l i t y i n d u s t r y , the i n c r e a s i n g r e t u r n s to s c a l e experienced i n the past, l e d to what seemed t o some economists to be an i m p o s s i b l e dilemma i n d e s i g n i n g an optimal r a t e s t r u c t u r e . With 1 S T h i s d i s c u s s i o n d e a l s only with economic e f f i c i e n c y - how to a l l o c a t e r e s o u r c e s so t h a t they cannot be f u r t h e r adjusted to i n c r e a s e s a t i s f a c t i o n without making at l e a s t one p a r t y l e s s s a t i s f i e d - and i g n o r e s the d i s t r i b u t i o n of r e s o u r c e s w i t h i n s o c i e t y . In order to d e r i v e an o p t i m a l s o c i a l welfare p o s i t i o n which i n c l u d e s c o n s i d e r a t i o n s of both e f f i c i e n c y and d i s t r i b u t i o n , an e x p l i c i t s o c i a l w e l f a r e f u n c t i o n i s r e q u i r e d . 30 marginal c o s t s below average c o s t s , the eguating of p r i c e s with marginal c o s t s would not meet the t o t a l revenue reguirement. In 1938, H o t e l l i n g s t a r t l e d the world of u t i l i t y r a t e theory by advocating t h a t the economic e f f i c i e n c y c r i t e r i o n become the prime c o n s i d e r a t i o n i n r a t e s e t t i n g . P r i c e s would be equated with s h o r t run marginal c o s t , and any revenue s h o r t f a l l s would be s u p p l i e d from general government revenues. C o n s i d e r a b l e debate over t h i s p r oposal ensued f o r the next 15 years, with p r a c t i t i o n e r s r e j e c t i n g the scheme and academic economists tending t o favour long run marginal cost as the b a s i s f o r determining an optimal resource a l l o c a t i o n . Within the l a s t decade t h e r e has been c o n s i d e r a b l e renewed i n t e r e s t i n the theory of r a t e s t r u c t u r e s , p a r t i c u l a r l y as a p p l i e d t o e l e c t r i c u t i l i t i e s . The circumstances of the debate have a l t e r e d d r a m a t i c a l l y , with the r i s i n g r e a l p r i v a t e and s o c i a l c o s t s a s s o c i a t e d with e l e c t r i c i t y g eneration and d i s t r i b u t i o n now suggesting t h a t marginal c o s t s exceed average c o s t s i n many cases. Some o f the i s s u e s of the e a r l i e r decades were r e s o l v e d . The apparent divergence between the economic e f f i c i e n c y and revenue s u f f i c i e n c y c r i t e r i a can be r e c o n c i l e d when i t i s r e a l i z e d that i t i s the marginal p r i c e t h a t must equal marginal cost f o r op t i m a l resource a l l o c a t i o n . Hence adjustments i n the i n t r a - m a r g i n a l p r i c e can t h e o r e t i c a l l y be made which w i l l enable both o b j e c t i v e s t o be met s i m u l t a n e o u s l y . On the i s s u e of s h o r t vs. long run marginal c o s t , i t was recognized t h a t i n an op t i m a l system the two are i d e n t i c a l once 1 6 I t should be recognized t h a t the t o t a l revenue requirements i n an economic sense have no necessary r e l a t i o n s h i p t o revenue requirements under an an h i s t o r i c a l c o s t accounting framework. the marginal c o s t s of c u r t a i l m e n t are i n c l u d e d i n the s h o r t run c o s t s . 1 7 For non-optimal systems, Turvey's (1968) su g g e s t i o n of using the present value of the change i n c o s t s f o r a demand change e f f e c t i v e l y uses an average (weighted by the r a t e o f s o c i a l time preference) of both s h o r t and long run marginal c o s t s . A commonly heard argument against the use of marginal c o s t p r i c i n g i n a p a r t i c u l a r i n d u s t r y r e v o l v e s around the theory of the second best. T h i s theory e s s e n t i a l l y s t a t e s t h a t no *a p r i o r i * c o n c l u s i o n can be drawn as t o the impact on s o c i a l welfare o f i n t r o d u c i n g marginal cost p r i c i n g i n one i n d u s t r y when at l e a s t one other i n d u s t r y does not use an economically e f f i c i e n t p r i c i n g c r i t e r i o n . The standard r e p l y t o t h i s argument i s t h a t one should s t i l l determine what the r e l e v a n t marginal c o s t s are f o r the p a r t i c u l a r i n d u s t r y under c o n s i d e r a t i o n . Then, when t r a n s f e r r i n g from a p a r t i a l t o a general e g u i l i b r i u m framework, adjustments i n t h a t i n d u s t r y ' s marginal p r i c e s may be d e s i r a b l e from an economic e f f i c i e n c y p e r s p e c t i v e i f s i g n i f i c a n t s u b s t i t u t e or complement products e x i s t whose p r i c i n g p r a c t i c e s do not s a t i s f y t h i s c r i t e r i o n . 1 7 C u r t a i l m e n t c o s t s are the c o s t s of doing without - the c o s t s i n c u r r e d by s o c i e t y as a r e s u l t of a shortage of e l e c t r i c i t y . For an o p t i m a l l y designed system, marginal s o c i a l c u r t a i l m e n t c o s t should equal marginal s o c i a l cost of adding e l e c t r i c a l supply c a p a c i t y . 32 3.2 Emergence Of The Methodology find Application Of M.C..P. although the basic theory establishing the merits of marginal cost p r i c i n g i s now well established in economic c i r c l e s , the application of t h i s theory remains much l e s s developed. Indeed, i t i s t h i s apparent d i f f i c u l t y that has led some to reject the economic e f f i c i e n c y objective as a central c r i t e r i o n i n rate d e s i g n . 1 8 In addition to the general debate over short vs. long run marginal costs, and the r e c o n c i l i a t i o n of economic e f f i c i e n c y and revenue s u f f i c i e n c y , the e l e c t r i c u t i l i t y l i t e r a t u r e has witnessed considerable controversy over the a l l o c a t i o n of marginal energy and capacity costs. This has manifested i t s e l f i n discussions on "peak load p r i c i n g " and the related problem of the " s h i f t i n g peak". The basic prevailing approach by economists today i s to charge both marginal operating and capacity costs to users during the system's peak periods, with off-peak users facing only marginal operating c o s t s . 1 9 Capacity costs are f u l l y allocated to peak periods since i t i s only t h i s demand that prompts new investment. The investment i n eguipment i d l e during off-peak periods represents "sunk costs" with an opportunity cost of zero. I f there are s i g n i f i c a n t v a r i a t i o n s in marginal costs within either of these periods, then a more f i n e l y structured rate schedule can be devised to correspond to these variations. Moreover, to the extent that the r e s u l t i n g rate structure would be expected to lead to s h i f t s i n the demand 1 8 See, for example, Lewis (1949). 1 9 See, for example, Berlin (1974) and Joskow (1976). 33 pattern, adjustments i n the rate structure would have to be made in a n t i c i p a t i o n of these movements. The f i r s t real attempt to apply marginal cost p r i c i n g p r i n c i p l e s to an e l e c t r i c u t i l i t y i s that of E l e c t r i c i t e de France (EDF) i n the early 1950*s. EDF was a nationalized power company supplying most of France with a system evenly comprised of hydro and thermal plants. The key problem in undertaking a marginal cost analysis was seen to be that of appropriately a l l o c a t i n g the heavy fixed costs associated with the production and d i s t r i b u t i o n of power. The u t i l i t y recognized that the correct way to calculate marginal costs would be to compare the cost changes associated with the reoptimization of the expansion and operation of the system that would r e s u l t from changes i n present and future demand. EDF found the application of t h i s approach d i f f i c u l t . To simplify the analysis, i t assumed the existence of an optimal system with short run marginal costs equal to long run marginal costs and proceeded to calculate the short run costs. Marginal generation costs were determined from the operating costs of thermal plants and, by tracing present and anticipated transmission l i n e flows, the e f f e c t i v e operating costs for the hydro f a c i l i t i e s were imputed. The marginal costs of transmission were the operating losses plus the c a p i t a l costs during those periods when the l i n e carried a f u l l load. Curtailment costs were also estimated. The r e s u l t i n g rates were di f f e r e n t i a t e d by time, season, voltage l e v e l and geographic location and were offered to the major customers. Since t h i s pioneering work, other u t i l i t i e s have undertaken economic analysis of their costs and have implemented rates 34 based, i n v a r y i n g degrees, on marginal c o s t p r i c i n g p r i n c i p l e s . T h i s approach i s g a i n i n g acceptance i n the United S t a t e s where a number of r e g u l a t o r y boards have r e c e n t l y ordered e l e c t r i c u t i l i t i e s under t h e i r j u r i s d i c t i o n to move i n t h i s d i r e c t i o n . ? 0 One of the more r e c e n t and thorough economic analyses of e l e c t r i c i t y c o s t i n g and p r i c i n g was t h a t undertaken by O n t a r i o Hydro ( 1 9 7 6 ) . 2 1 The study recommended new r a t e s t r u c t u r e s based upon marginal cost p r i c i n g p r i n c i p l e s , and the methodology employed to determine the r e l e v a n t marginal c o s t s i s r e p r e s e n t a t i v e of the approach now most common i n the U.S. 2 2 L i k e EDF, O n t a r i o Hydro does not develop a methodology based on the pure theory of marginal c o s t e s t i m a t i o n , but r a t h e r employs v a r i o u s " s h o r t c u t s " which i n v o l v e a n a l y z i n g c e r t a i n p a r t s of the e l e c t r i c system.,Marginal generation c a p a c i t y c o s t s are e s s e n t i a l l y taken to be the a n n u a l i z e d c o s t s of a gas t u r b i n e peaking p l a n t . Marginal t r a n s m i s s i o n c o s t s are a l l a l l o c a t e d to c a p a c i t y and are determined by a n n u a l i z i n g f u t u r e r e a l e x p e n d i t u r e s on t r a n s m i s s i o n f a c i l i t i e s . These c o s t s are then d i v i d e d among v a r i o u s b r o a d l y d e f i n e d p e r i o d s with most being a l l o c a t e d t o those times with the g r e a t e s t l o s s of l o a d 2 0 See, f o r example. P u b l i c S e r v i c e Commission of Wisconsin (1974) and State of New York, P u b l i c S e r v i c e Commission (1976). 2 1 although the Board of D i r e c t o r s of O n t a r i o Hydro has f o r m a l l y accepted the u n d e r l y i n g p r i n c i p l e t h a t e f f i c i e n c y i n the a l l o c a t i o n and use of r e s o u r c e s i n producing e l e c t r i c energy i s the a p p r o p r i a t e p r i c i n g o b j e c t i v e , i t has not taken any p o s i t i o n on the s p e c i f i c recommendations of the study. 2 2 One reason f o r t h i s i s t h a t N a t i o n a l Economic fiesearch A s s o c i a t e s , a l a r g e New York economic c o n s u l t i n g f i r m , undertook much of the marginal c o s t e s t i m a t i o n f o r O n t a r i o Hydro. I t has performed s i m i l a r work f o r many of the e l e c t r i c u t i l i t i e s i n the United S t a t e s now going through t h i s process. C i c c h e t t i * s (1976) manual on marginal c o s t p r i c i n g advocates the same b a s i c approach. 35 p r o b a b i l i t y . M a r g i n a l e n e r g y c o s t s a r e t a k e n t o be a w e i g h t e d a v e r a g e o f t h e h i g h e s t v a r i a b l e c o s t U n i t s a s s o c i a t e d w i t h e n e r g y p r o d u c t i o n d u r i n g t h e s e d i f f e r e n t p e r i o d s . A l l c o s t s a r e t h o s e f a c e d by O n t a r i o H y d r o and t h e s e i n i t i a l e s t i m a t e s a r e n o t e x p l i c i t l y r e c a l c u l a t e d a s a r e s u l t o f demand p a t t e r n s h i f t s which would be e x p e c t e d f r om t h i s c h a n g e . T h e s e t i m e - d i f f e r e n t i a t e d m a r g i n a l e n e r g y and c a p a c i t y c o s t s a r e t h e n u s e d as a b a s i s f o r s e t t i n g an o p t i m a l r a t e s t r u c t u r e , a p p r o p r i a t e l y a d j u s t e d f o r c o n s i d e r a t i o n s o f r e v e n u e c o n s t r a i n t s , e g u i t y , c o s t o f m e t e r i n g , e t c . 3 T3 D e v e l o p i n g An M, C. P. M e t h o d o l o g y F o r B..C._ Hydro B.C. Hydro has n e v e r f o r m a l l y a d o p t e d e c o n o m i c e f f i c i e n c y as a g o a l i n i t s r a t e s e t t i n g p o l i c y . I t has, however, p u b l i c l y s t a t e d t h a t i t s r a t e s a r e , and s h o u l d c o n t i n u e t o be, b a s e d on " c o s t s " . The c u r r e n t f u l l y d i s t r i b u t e d a v e r a g e c o s t i n g m e t hodology u s e d by B.C. Hydro t o d e t e r m i n e " c o s t o f s e r v i c e " has no r e l a t i o n s h i p w i t h an a p p r o p r i a t e m a r g i n a l c o s t i n g a p p r o a c h . I t s prime r o l e i s t o a l l o c a t e a c c o u n t i n g c o s t s amongst v a r i o u s u s e r c l a s s e s t o e n s u r e t h a t e a c h c l a s s c o n t r i b u t e s enough r e v e n u e t o e n a b l e t h e A u t h o r i t y t o meet i t s n e t income o b j e c t i v e . 2 3 T h i s somewhat a r b i t r a r y , b a c k w a r d - l o o k i n g a p p r o a c h 2 3 The c h o i c e o f a l l o c a t i o n method has an i m p o r t a n t i n f l u e n c e on t h e r e l a t i v e s h a r e o f t o t a l c o s t s a t t r i b u t e d t o e a c h c l a s s . Thus t h e B.C. Hydro method, w i t h i t s h e a v y a l l o c a t i o n o f c o s t s t o c a p a c i t y , f a v o u r s t h e h i g h l o a d f a c t o r c l a s s e s ( i n d u s t r i a l ) a t t h e e x p e n s e o f t h e low l o a d f a c t o r c o n s u m e r s ( r e s i d e n t i a l ) . 36 i s then used as a b a s i s f o r determining marginal as w e l l as average r a t e s . I t f a i l s as an a p p r o p r i a t e b a s i s f o r s e t t i n g p r i c e s c o n s i s t e n t with the economic e f f i c i e n c y c r i t e r i o n i n a number of fundamental ways. In some cases i t simply uses the wrong c o s t s from an economic p e r s p e c t i v e . Costs e x t e r n a l t o the A u t h o r i t y are ignored , and reso u r c e s are valued at t h e i r c o s t t o the u t i l i t y which d i f f e r s s i g n i f i c a n t l y from t h e i r t r u e o p p o r t u n i t y c o s t i n some i n s t a n c e s . Commitments made at d i f f e r e n t times are compared d i r e c t l y d e s p i t e subsequent i n f l a t i o n and d i f f e r i n g t e c h n o l o g i e s . Thus the average h i s t o r i c a l c o s t d e p r e c i a t i o n charge i s below both i t s own marginal l e v e l and i t s i n f l a t i o n - adjusted average l e v e l . S i m i l a r l y , the average nominal i n t e r e s t c o s t s used i n the " c o s t o f s e r v i c e " methodology are s u b s t a n t i a l l y below t h e i r marginal nominal c o s t . In other cases, B.C. Hydro's c o s t a l l o c a t i o n i s done i n an a r b i t r a r y way and important cost r e s p o n s i b i l i t i e s are l o s t . The s p l i t between energy and c a p a c i t y i s on the b a s i s o f e x i s t i n g p l a n t r a t h e r than on the cause of b u i l d i n g new f a c i l i t i e s . Time- d i f f e r e n t i a t e d c o s t s are b u r i e d s i n c e a l l c o s t s are lumped together and then averaged. These weaknesses i n the c o s t i n g methodology are f u r t h e r i n t e n s i f i e d by the manner i n which i t i s a p p l i e d i n r a t e s e t t i n g . The " f r o n t end l o a d i n g " of the f i x e d charges f o r r e s i d e n t i a l and commercial customers r e s u l t s i n marginal energy r a t e s below even the c o s t s determined on the f u l l y d i s t r i b u t e d average c o s t method. For the l a r g e r customers, the heavy peak demand charges are based p r i m a r i l y on the i n d i v i d u a l customer's 37 demand p a t t e r n with l i t t l e regard f o r i t s c o i n c i d e n c e or otherwise with t h a t of the system. U n f o r t u n a t e l y , the technigues t h a t have been used t o determine marginal c o s t s f o r other e l e c t r i c u t i l i t i e s have some of these weaknesses and do not appear, i n any case, t o be p a r t i c u l a r l y r e l e v a n t f o r B.C. Hydro. T h i s stems i n part from B.C. Hydro's very l a r g e and growing h y d r o - e l e c t r i c g e n e r a t i o n base, which d i s t i n g u i s h e s i t from other systems i n two s i g n i f i c a n t r e s p e c t s . The f i r s t i s the extremely c a p i t a l - i n t e n s i v e nature of the system with c o n s e g u e n t i a l l y low marginal o p e r a t i n g c o s t s . The second r e l a t e s to the e n e r g y - c r i t i c a l nature of the system. Most c u r r e n t marginal c o s t i n g technigues i m p l i c i t l y assume the e x i s t e n c e of an e c o n o m i c a l l y optimal e l e c t r i c a l system t h a t i s both energy and c a p a c i t y - c r i t i c a l and i n which the marginal c o s t s are independent of the s i z e and d i r e c t i o n of the demand v a r i a t i o n . These assumptions may be reasonable f o r some systems and thus y i e l d a good approximation of marginal c o s t s . However, they are c e r t a i n l y not v a l i d f o r B.C. Hydro. The B.C. Hydro system i s not o p t i m a l l y designed, i n the economic sense t h a t the s h o r t run average c o s t curve i s c u r r e n t l y above the long run average c o s t curve, because of the post-1973 major i n c r e a s e s i n the p r i c e of petroleum. Hence new h y d r o - e l e c t r i c p r o j e c t s are estimated t o produce cheaper energy than the g a s - f i r e d Burrard thermal p l a n t (when gas i s p r i c e d a t i t s o pportunity c o s t ) . Thus to r e l y e x c l u s i v e l y on the marginal o p e r a t i n g c o s t s of Burrard as the a p p r o p r i a t e marginal energy r a t e would overestimate these c o s t s . 38 The f a c t that the B.C. Hydro system i s not c u r r e n t l y both energy and c a p a c i t y - c r i t i c a l a l s o has i n t e r e s t i n g i m p l i c a t i o n s . New generating p r o j e c t s t h a t produce both energy and c a p a c i t y , but that are advanced or re t a r d e d only because of changes i n the energy demand f o r e c a s t , should have the r e s u l t a n t c o s t changes a l l o c a t e d s o l e l y to the energy component. So too with the a s s o c i a t e d t r a n s m i s s i o n l i n e s l i n k i n g the new p r o j e c t to the load c e n t r e , a procedure counter to both the " c o s t of s e r v i c e " and the c u r r e n t marginal c o s t i n g methodologies. Changes i n the peak demand f o r e c a s t w i l l a f f e c t the t i m i n g o f the c a p a c i t y - o n l y p r o j e c t s i n the 1980*s, but these c o s t changes should be a p p r o p r i a t e l y discounted i n s e t t i n g today's r a t e s . The t h i r d f a l s e assumption concerns the l i n e a r i t y and symmetry of the response of c o s t s t o demand changes. For example, an i n c r e a s e i n the annual energy demand w i l l g e n e r a l l y l e a d to i n c r e a s e d use of the expensive B u r r a r d thermal p l a n t . However, a s u b s t a n t i a l annual decrease w i l l f i r s t be met by s h u t t i n g down Burrard and then by s p i l l i n g water over dams (assuming no export market i s a v a i l a b l e ) , with very l i t t l e c o s t savings t o Hydro or s o c i e t y . Other n o n - l i n e a r i t i e s w i l l be evident because of i n d i v i s i b i l i t i e s and somewhat a r b i t r a r y t e c h n i c a l c r i t e r i a . 2 * As a r e s u l t of these and other important weaknesses i n the c u r r e n t marginal c o s t p r i c i n g methodology, a d i f f e r e n t approach 2 * For example, the t e c h n i c a l energy or c a p a c i t y c r i t e r i a may cause a s m a l l change i n a n t i c i p a t e d demand to a u t o m a t i c a l l y t r i g g e r the advancement of a p r o j e c t by a f u l l year. An economic a n a l y s i s might suggest s o c i e t y would be b e t t e r o f f f a c i n g the i n c r e a s e d r i s k s of an e l e c t r i c i t y shortage than i n c u r r i n g the e x t r a r e a l c o s t s of advancing the p r o j e c t by a year. 39 i s r e g u i r e d . The b a s i c method t h a t we w i l l a d o p t i s t h a t o u t l i n e d by EDF and l a t e r r e f o r m u l a t e d and c l a r i f i e d by T u r v e y ( 1 9 6 8 ) . I t r e v o l v e s a r o u n d t h e f u n d a m e n t a l meaning o f m a r g i n a l c o s t i n a dynamic c o n t e x t - t h e change i n t h e p r e s e n t v a l u e o f s o c i e t y ' s c o s t s a s s o c i a t e d w i t h a m a r g i n a l change i n t h e p r e s e n t o r f u t u r e demand f o r e l e c t r i c i t y . u s i n g c o mputer s i m u l a t i o n t e c h n i g u e s , we s h a l l b u i l d a model which w i l l p l a n and o p e r a t e B.C. H y d r o ' s i n t e g r a t e d s y s t e m i n a c o s t - m i n i m i z i n g way, s u b j e c t t o v a r i o u s t e c h n i c a l c o n s t r a i n t s , b a s e d upon a g i v e n e l e c t r i c a l demand f o r e c a s t . A c h a n g e i n t h e demand f o r e c a s t w i l l t h e n be i n t r o d u c e d and t h e o p e r a t i o n and d e s i g n o f t h e e l e c t r i c s y s t e m w i l l a d j u s t i t s e l f a c c o r d i n g l y . The p r e s e n t v a l u e o f t h e a s s o c i a t e d c o s t d i f f e r e n c e d i v i d e d by t h e p r e s e n t v a l u e o f t h e changed q u a n t i t y o f k i l o w a t t - h o u r s w i l l y i e l d t o d a y ' s m a r g i n a l c o s t p e r k i l o w a t t - h o u r r e s u l t i n g f r o m t h e c h a n g e . By a l t e r i n g t h e s y s t e m l o a d f a c t o r o f t h i s h y p o t h e t i c a l change i n demand, th e m a r g i n a l c o s t c a n be a p p r o p r i a t e l y a l l o c a t e d between t h e e n e r g y and c a p a c i t y components. F o r example, t h e a d d i t i o n a l c o s t s r e s u l t i n g from a demand i n c r e a s e t h a t f a l l s p a r t l y o n t h e s y s t e m ' s peak p e r i o d r a t h e r t h a n t h e same i n c r e a s e o c c u r r i n g t o t a l l y i n o f f - p e a k p e r i o d s w i l l y i e l d t h e m a r g i n a l c o s t s a s s o c i a t e d w i t h a change i n peak demand. A l l c o s t s u s e d i n t h i s e c o n o m i c a n a l y s i s w i l l be e x p r e s s e d i n r e a l t e r m s u s i n g 1976 d o l l a r s . A one y e a r d e l a y i n t h e commencement o f a c o n s t r u c t i o n p r o j e c t w i l l , a l l t h i n g s b e i n g e q u a l , n o t a f f e c t i t s r e a l c o s t d e s p i t e a l i k e l y i n c r e a s e i n i t s n o m i n a l c o s t due t o i n f l a t i o n . I t i s t h e r e l a t i v e c o s t o f t h e p r o j e c t , i n t e r m s o f t h e f o r e q o n e a l t e r n a t i v e u s e s o f t h e 40 resources employed, t h a t i s i m p o r t a n t . 2 5 i n f a c t , the one year delay w i l l , a l l t h i n g s being equal, reduce the c o s t of the p r o j e c t t o s o c i e t y (as viewed from today) due t o the d i s c o u n t i n g of f u t u r e c o s t s . These c o s t s should be discounted by s o c i e t y ' s r e a l r a t e of s o c i a l time pre f e r e n c e , the premium we a t t a c h to present over f u t u r e consumption. The c o s t s we are i n t e r e s t e d i n are o p p o r t u n i t y c o s t s - what s o c i e t y would have r e c e i v e d , and hence must f o r e g o , had the resources been put to a l t e r n a t i v e uses. Those investments already made are "sunk c o s t s " with zero o p p o r t u n i t y c o s t and w i l l not be i n c l u d e d i n t h i s a n a l y s i s . I t i s the v a r i a b l e o p e r a t i n g and f u t u r e investment c o s t s that have a p o s i t i v e o p p o r t u n i t y cost and which w i l l be focussed upon here. The present value of these c o s t s w i l l r i s e ( f a l l ) t o meet a demand i n c r e a s e (decrease). The economic c o s t s used i n t h i s a n a l y s i s w i l l d e v i a t e i n s e v e r a l important ways from c o s t s as measured by B.C. Hydro. With the exception of f u e l , a l l the A u t h o r i t y ' s o p e r a t i n g c o s t s w i l l be assumed to be p r i c e d at t h e i r f u l l o p p o r t u n i t y c o s t . 2 6 Natural gas w i l l be valued at i t s export p r i c e , more than twice what B.C. Hydro now pays t o burn gas i n i t s thermal p l a n t s . T h i s i s p a r t i c u l a r l y f i t t i n g s i n c e gas export c o n t r a c t s at t h i s p r i c e are not being f u l f i l l e d because of upstream demand 2 5 To the extent t h a t "money i l l u s i o n " e x i s t s , the r e a l c o s t s may, i n f a c t , vary because of i n f l a t i o n . I t i s d i f f i c u l t t o determine 'a p r i o r i ' the net e f f e c t of t h i s i l l u s i o n s i n c e i t might r a i s e r e a l c o s t s i n some cases (eg. c o s t of c a p i t a l ) and lower i t i n others (eg. cost of l a b o u r ) . 2 6 To the extent that r e s o u r c e s used by B.C. Hydro would otherwise be underemployed, t h i s assumption overestimates t r u e opportunity c o s t s . An obvious example i s a c o n s t r u c t i o n p r o j e c t i n a high unemployment area. 41 i n B r i t i s h Columbia. S i m i l a r l y , f u t u r e c o a l p r o d u c t i o n from B.C. d e p o s i t s w i l l be valued a t the h i g h e s t net p r i c e t h a t i t could have r e c e i v e d elsewhere. Annual water l i c e n c e f e e s w i l l be i m p l i c i t l y assumed t o re p r e s e n t the o p p o r t u n i t y c o s t o f the r i v e r a f f e c t e d by the power p r o j e c t . 2 7 C o n s t r u c t i o n c o s t estimates w i l l be a p p r o p r i a t e l y a d j u s t e d i n l i g h t of past experience with changes i n r e a l c o s t s from p r e l i m i n a r y planning t o f i n a l estimate t o a c t u a l c o s t . Although the r e l a t i v e c o s t of each p r o j e c t i s a l l that i s important when s e l e c t i n g which p r o j e c t t o proceed wit h , the a b s o l u t e c o s t o f the l e a s t expensive one i s r e g u i r e d t o decide whether the p r o j e c t should proceed at a l l . These est i m a t e s w i l l i n c l u d e expenditures r e g u i r e d to reduce some of the ne g a t i v e e x t e r n a l i t i e s a s s o c i a t e d with the p r o j e c t s . D e p r e c i a t i o n charges w i l l i e based on the l i f e o f the average Canadian n o n r e s i d e n t i a l investment, r a t h e r than on the expected l i f e of the p a r t i c u l a r a s s e t being d e p r e c i a t e d . 2 8 Had the c a p i t a l not been i n v e s t e d i n a dam, f o r example, i t c o u l d have gone i n t o home i n s u l a t i o n , equipment modernization or petroleum development. The s h o r t e r l i v e s of the c a p i t a l i n these p r o j e c t s would have ensured a f a s t e r repayment and subsequent combination with other resources t o r a i s e s o c i a l w e l f a r e . S t r a i g h t l i n e d e p r e c i a t i o n over the "oppo r t u n i t y l i f e " of the 2 7 The v a l i d i t y o f t h i s assumption i s suspect s i n c e water l i c e n c e fees are uniform throughout the province - they do not respond to the d i f f e r i n g a l t e r n a t i v e use values of d i f f e r e n t dam s i t e s . T h i s weakness w i l l be p a r t i a l l y overcome by i n c l u d i n g the a d d i t i o n a l expenses r e q u i r e d to m i t i g a t e some of the e x t e r n a l c o s t s a s s o c i a t e d with each p r o j e c t . 2 8 I owe t h i s approach t o H e l l i w e l l ( p r i v a t e d i s c u s s i o n ) and Gaffney {1974, 1976). 42 investment w i l l l e a d to a con s t a n t charge i n r e a l terms, or one whose nominal l e v e l r i s e s each year with the r a t e of i n f l a t i o n . 2 9 In determining the a p p r o p r i a t e r e a l cost o f c a p i t a l (mainly i n t e r e s t expense), the o p p o r t u n i t y c o s t concept i s again employed. Investment funds being spent by B.C. Hydro r e p r e s e n t , to some degree, money being d i v e r t e d from investment i n other s e c t o r s o f B r i t i s h Columbia. To the extent that, t h i s foregone investment would have been i n the p r i v a t e s e c t o r , i t would have generated a d d i t i o n a l r e t u r n s to s o c i e t y i n the form of c o r p o r a t e taxes on income and c a p i t a l . 3 0 These foregone r e t u r n s to s o c i e t y from a l t e r n a t i v e use of the investment funds should be i n c l u d e d i n the o p p o r t u n i t y c o s t of c a p i t a l . There are s e v e r a l other c o s t s t o s o c i e t y which are not r e f l e c t e d i n the c o s t of c a p i t a l a c t u a l l y faced by B.C. Hydro. Funds borrowed i n Canada w i l l tend to push up i n t e r e s t r a t e s which w i l l reduce other investment with d i r e c t or i n d i r e c t c o s t s to B r i t i s h Columbia. C a p i t a l borrowed i n the i n t e r n a t i o n a l market w i l l tend i n i t i a l l y to r a i s e the value of the Canadian d o l l a r (under a f l e x i b l e exchange rate) with negative i m p l i c a t i o n s f o r B.C.'s h e a v i l y e x p o r t - o r i e n t e d i n d u s t r y . Also, the guaranteeing of the B.C. Hydro debt by the P r o v i n c e has a shadow p r i c e a s s o c i a t e d with i t i n terms of reduced a v a i l a b i l i t y and/or higher p r i c e o f c a p i t a l f o r other government-backed 2 9 T h i s i s i n c o n t r a s t t o the e x i s t i n g s t r a i g h t l i n e d e p r e c i a t i o n method which y i e l d s c onstant nominal ( f a l l i n g r e a l ) annual charges. T h i s reduces the g u a n t i t y of i n t e r n a l l y - generated funds and may l e a d to " c a p i t a l exhaustion". 3 0 I t might a l s o have generated a d d i t i o n a l r e t u r n s from s c h o o l taxes s i n c e B.C. Hydro has a p a r t i a l exemption from these l o c a l taxes. 43 p r o j e c t s , 3 1 as w e l l as fewer f i n a n c i a l p o l i c y o p t i o n s open t o the p r o v i n c i a l government. T h i s shadow p r i c e could be r e f l e c t e d i n an i n t e r e s t premium over the nominal coupon r a t e . In t h i s paper, th e r e a l o p p o r t u n i t y c o s t o f c a p i t a l w i l l be taken to be the average Canadian before-tax r e a l c o s t o f c a p i t a l and w i l l be a p p l i e d to the net (undepreciated) r e a l c a p i t a l s t o c k . I t exceeds the r e a l r a t e of s o c i a l time p r e f e r e n c e , approximated by the r e a l a f t e r - t a x r e t u r n s on v i r t u a l l y r i s k - f r e e bonds, used t o d i s c o u n t aggregate f u t u r e c o s t s . 3 2 The r e a l s o c i a l time preference r a t e r e p r e s e n t s s o c i e t y ' s u n w i l l i n g n e s s to exchange f u t u r e f o r present consumption, while the r e a l o p p o r t u n i t y cost of c a p i t a l r e f l e c t s the a l t e r n a t i v e r e t u r n s s o c i e t y would have r e c e i v e d from investment of the funds elsewhere. The two are separated by a tax and r i s k wedge. The use of the two d i f f e r e n t r a t e s d i f f e r s from the p r a c t i c e of B.C. Hydro and o t h e r s where the r a t e s are combined i n t o a s i n g l e s o c i a l d i s c o u n t r a t e . 3 3 Once t h i s b a s i c framework has been e s t a b l i s h e d , we s h a l l be i n t e r e s t e d i n determining the r e l e v a n t marginal c o s t s a s s o c i a t e d 3 1 T h i s problem has become p a r t i c u l a r l y acute i n O n t a r i o where the p r o v i n c i a l government r e c e n t l y ordered On t a r i o Hydro to cut back over $5 b i l l i o n i n i t s proposed c a p i t a l budget to 1985 because of concern over the s t r a i n the a s s o c i a t e d borrowing would have imposed on O n t a r i o ' s c r e d i t . There are some i n d i c a t i o n s of concern i n V i c t o r i a about the s i z e of B.C. Hydro *s f u t u r e borrowing p l a n s . T h i s may be w e l l based i n view of r e p o r t s of f u t u r e l a r g e c a p i t a l reguirements by the p r o v i n c i a l l y - o w n e d B.C. Railway Company. 3 2 The i d e a of using separate r a t e s of s o c i a l time preference and of c o s t of c a p i t a l f o l l o w s Campbell (1975) and Marglin 41963). For a d i s c u s s i o n o f the assumptions i m p l i c i t i n such an approach, see Eeisbeck (1976). 3 3 The standard r e a l d i s c o unt r a t e used by B.C. Hydro i s 10.0 percent. In t h i s a n a l y s i s , the r e a l o p p o r t u n i t y c o s t of c a p i t a l w i l l be 10.5 percent and the r e a l r a t e of s o c i a l time p r e f e r e n c e w i l l be 5.0 percent. 44 with demand shocks of v a r i o u s s i z e s , d i r e c t i o n and d u r a t i o n . Of p a r t i c u l a r i n t e r e s t w i l l be shocks of a constant s i z e extending from the present to the end of the s i m u l a t i o n p e r i o d . I t i s t h i s decrease i n c o s t s which s o c i e t y w i l l f a c e as a r e s u l t c f a customer of B.C. Hydro making a net e l e c t r i c i t y - s a v i n g adjustment to h i s c a p i t a l s tock. Only i f t h i s customer f a c e s a marginal p r i c e egual to t h i s marginal c o s t w i l l s o c i e t y ' s resources be most e f f i c i e n t l y used i n the long run. Adjustments can then be made to t h i s b a s i c marginal cost and p r i c e i n l i g h t of the impact of s h o r t e r run demand v a r i a t i o n s . T h i s a n a l y s i s w i l l c o n c e n t r a t e on the bulk power s i d e of B.C. Hydro's i n t e g r a t e d e l e c t r i c system - the g e n e r a t i o n and tra n s m i s s i o n s e c t o r s . The A u t h o r i t y ' s own understanding and a n a l y s i s of the lower l e v e l t r a n s m i s s i o n and d i s t r i b u t i o n system i s not as thorough as f o r the bulk s e c t o r , and very l i t t l e p u b l i s h e d i n f o r m a t i o n i s a v a i l a b l e t o the independent r e s e a r c h e r . As we have seen, however, i t i s the bulk system t h a t i s r e s p o n s i b l e f o r two- t h i r d s of Hydro's t o t a l investment programme i n the next 5 years, as w e l l as being the s e c t o r t h a t d i s t i n g u i s h e s i t from other e l e c t r i c systems. Consequently, we s h a l l focus on the marginal- c o s t s a s s o c i a t e d with s e r v i n g l a r g e customers at high v o l t a g e l e v e l s , although estimates w i l l a l s o be made of the a d d i t i o n a l c o s t s i n v o l v e d i n s u p p l y i n g the sm a l l e r customers i n the system. 45 3*4 Summary In t h i s c h a p t e r , we have t r a c e d the development o f the theory and methodology o f marginal c o s t p r i c i n g , p a r t i c u l a r l y as i t a p p l i e s t o e l e c t r i c u t i l i t i e s . In the l a s t s e c t i o n we have o u t l i n e d the b a s i c approach t h a t w i l l be used i n the next chapters t o c a l c u l a t e the a p p r o p r i a t e marginal c o s t s f o r B.C. Hydro's e l e c t r i c system. The theory of marginal c o s t p r i c i n g as an e f f i c i e n t way of a l l o c a t i n g s o c i e t y ' s s c a r c e r e s o u r c e s i s now well e s t a b l i s h e d and accepted, at l e a s t amongst economists. The methodology f o r determining and implementing such a theory remains somewhat l e s s developed. The r a t e s e t t i n g procedures c u r r e n t l y i n use by B.C. Hydro do not c l a i m t o be, and are not, based upon such a p r i n c i p l e . The marginal c o s t p r i c i n g methodology being developed by Ontario Hydro and other North American e l e c t r i c u t i l i t i e s may provide reasonable approximations i n some i n s t a n c e s , but w i l l not generate meaningful r e s u l t s i n the case of B.C. Hydro. The methodology developed i n t h i s paper r e l i e s upon the b a s i c d e f i n i t i o n of marginal c o s t i n the dynamic sense, and employs e x p l i c i t economic c o s t s i n i t s a n a l y s i s . 46 l i THE STRUCTURE OF THE MODEL 4. 1 I n t r o d u c t i o n In t h i s chapter, we d e s c r i b e the computer s i m u l a t i o n model designed to estimate marginal c o s t s f o r B.C. Hydro's i n t e g r a t e d e l e c t r i c system. We begin by p r o v i d i n g an overview of the model and i t s component p a r t s . Subsequent s e c t i o n s c o n t a i n more d e t a i l about each of these p a r t s , p r o v i d i n g , where a p p r o p r i a t e , important background on the theory, assumptions, c a l c u l a t i o n s and modelling i n v o l v e d . The b a s i c f u n c t i o n of the present model i s to take exogenous e n g i n e e r i n g and f i n a n c i a l data and, given a f u t u r e e l e c t r i c a l demand p r o j e c t i o n , determine the average accounting and marginal economic c o s t s r e s u l t i n g from the o p t i m a l design and o p e r a t i o n of the B.C. Hydro system. The model operates on an annual b a s i s from 1975 to 2059 and has the a b i l i t y t o b r i n g on a d d i t i o n a l g e n e r a t i o n p r o j e c t s s u f f i c i e n t t o meet a qu a d r u p l i n g of the 1975 l e v e l of demand. The values f o r the i n i t i a l year of the s i m u l a t i o n p e r i o d are based on a c t u a l f i g u r e s r e p o r t e d i n B.C. Hydro's Annual Heport f o r t h a t year. Future demand and c o s t e s t i m a t e s a r e d e r i v e d l a r g e l y from i n f o r m a t i o n contained i n the 1975 Task Force Report (B.C. Hydro, 1975b). F i n a n c i a l data are p r i m a r i l y from a r e c e n t Prospectus of the A u t h o r i t y (B.C. Hydro, 1976b). C l a r i f i c a t i o n , updating and more d e t a i l were provided by numerous o f f i c i a l s w i t h i n B.C. Hydro. The model begins by t a k i n g i n f o r m a t i o n contained i n two •47 p o l i c y s u b r o u t i n e s - PGLD1 and P0LS1, The former s u p p l i e s e l e c t r i c a l energy demand f o r e c a s t s and the l a t t e r i n f o r m a t i o n on e x i s t i n g and committed gener a t i o n p r o j e c t s . Subroutine DEMAND i s then c a l l e d to c a l c u l a t e peak demand reguirements and t o i n t r o d u c e any changes i n f u t u r e demand f o r e c a s t s . By f a r the l o n g e s t and most d e t a i l e d s ubroutine i n the model i s SUPPLY. I t c o n t a i n s e n g i n e e r i n g (energy c a p a b i l i t y and peaking c a p a c i t y ) and economic (investment p r o f i l e ) data f o r each major gener a t i o n and t r a n s m i s s i o n p r o j e c t . I t a l s o has in f o r m a t i o n on the investment r e g u i r e d f o r downstream f a c i l i t i e s ( s ub-transmission, t r a n s f o r m a t i o n , d i s t r i b u t i o n , etc.) to meet i n c r e a s e d e l e c t r i c a l demands. / Subroutine MCOST c o n t a i n s the op e r a t i n g c o s t s f o r each type of gen e r a t i o n f a c i l i t y and, using the i n f o r m a t i o n on each major p r o j e c t from SUPPLY, i s a b l e to perform an economic a n a l y s i s of these p r o j e c t s . The r e s u l t i n g l e a s t - c o s t ranking of p o t e n t i a l p r o j e c t s i s i n c o r p o r a t e d i n su b r o u t i n e APPROVE., T h i s s u b r o u t i n e compares f u t u r e expected energy and peak demand with f u t u r e expected energy c a p a b i l i t y and peak c a p a c i t y . When a s h o r t f a l l i n e i t h e r the energy or c a p a c i t y component i s f o r e c a s t , i t approves the next l e a s t expensive p r o j e c t i n time f o r production to commence when r e q u i r e d . Subroutine SUPPLY takes t h i s i n f o r m a t i o n and c o n s t r u c t s the new system, f u l l y a c c o untinq f o r v a r i o u s e n g i n e e r i n g and economic v a r i a b l e s f o r each type o f p r o j e c t . I t a l s o operates the system i n a c o s t minimizing f a s h i o n i n l i g h t of the c u r r e n t demand f a c i n g B.C. Hydro i n each time p e r i o d . These d e c i s i o n s on the expansion and o p e r a t i o n of the system are fed i n t o s u b r o u t i n e COSTS which c a l c u l a t e s both the 48 a s s o c i a t e d accounting and economic c o s t s . The former i s done by c a r e f u l t r a c k i n g of o p e r a t i n g c o s t s , l o c a l and p r o v i n c i a l t a x e s , i n t e r e s t payments, d e p r e c i a t i o n charges, f i n a n c i a l reguirements, e t c . , and y i e l d s the (average h i s t o r i c a l accounting) " c o s t o f s e r v i c e " of a KWH. The economic a n a l y s i s determines the ap p r o p r i a t e marginal c o s t per KWH using the b a s i c approach o u t l i n e d i n the l a s t chapter. F i n a l l y , s u b r o u t i n e BITES a d j u s t s average p r i c e s f o r t h e v a r i o u s customer c l a s s e s to ensure that the net income o b j e c t i v e i s met. With that b r i e f overview of the b a s i c o p e r a t i o n o f the model, we t u r n now t o examine i n more d e t a i l the component p a r t s . 4.2 POLD1 And POLS 1 Subroutine P0LD1 co n t a i n s net e l e c t r i c a l energy demand f o r e c a s t s f o r the pe r i o d 1975-1990 as provided i n the 1975 Task Force Report. T h i s provides a base case from which we l a t e r i n t r o d u c e d e v i a t i o n s . In a l l cases, demand i s assumed to s t a b i l i z e at the 1990 l e v e l f o r t h e d u r a t i o n of the s i m u l a t i o n p e r i o d . The demand f o r e c a s t f o r B.C. Hydro's i n t e g r a t e d e l e c t r i c system i s s p l i t between r e s i d e n t i a l , g e n e r a l and bulk customers and, i n a d d i t i o n , i n c l u d e s the a n t i c i p a t e d i n c r e m e n t a l reguirements of a p r i v a t e u t i l i t y . 3 * The expected number of e l e c t r i c i t y customers i s a l s o read i n . The net energy demand 3 4 West Kootenay Power and L i g h t Company, a p r i v a t e l y owned u t i l i t y s u p p l y i n g r e s i d e n t s i n the s o u t h - c e n t r a l part o f B r i t i s h Columbia, a n t i c i p a t e s r e l y i n g on B.C. Hydro f o r e l e c t r i c i t y when the demands f a c i n g i t exceed i t s own generating c a p a b i l i t y . 49 f o r e c a s t s i x years hence f o r each customer c l a s s i s then fed i n f o r each year i n the p e r i o d 1975-1984. T h i s i n f o r m a t i o n i s c o n s i s t e n t with the net energy demand expected f o r each year i n the 15 year p e r i o d and i s used l a t e r to determine when new generation and t r a n s m i s s i o n p r o j e c t s , with lead times o f up to s i x years, should be approved. Subroutine P0LS1 provides some b a s i c i n f o r m a t i o n on the supply s i d e of the B.C. Hydro system. Approval dates f o r p r o j e c t s a l r e a d y committed are read i n . Adjustments i n the r e a l c o s t s of v a r i o u s components of the system are made here. The r e a l c a p i t a l c o s t of a l l f u t u r e g e n e r a t i o n p r o j e c t s i s assumed to be 25 percent above the e q u i v a l e n t 1976 estimate although s e n s i t i v i t y analyses using 0 and 50 percent are performed. T h i s adjustment i s i n c l u d e d because of a r e l u c t a n c e by the author to accept the accuracy o f i n i t i a l p l a n n i n g estimates i n l i g h t of r e c e n t e x p e r i e n c e s by B.C. Hydro and others i n v o l v e d with the c o n s t r u c t i o n of l a r g e custom- engineered p r o j e c t s i n North America.35 These upward r e v i s i o n s c o u l d r e s u l t from more d e t a i l e d c o s t e s t i m a t i o n , higher standards being r e q u i r e d or unforeseen problems du r i n q c o n s t r u c t i o n . 3 6 The s p e c i f i c number 3 S Witness, f o r example, the r e c e n t Kootenay Canal p r o j e c t by B.C. Hydro and t h e Trans-Alaska o i l p i p e l i n e , Syncrude p l a n t and Montreal Olympics by o t h e r s . A r l o n T u s s i n q (1976) has compared c o s t e s t i m a t o r s with accountants i n t h a t they both p r e f e r a s o l i d , e m p i r i c a l l y based f i q u r e t o a r e a l i s t i c one. as Examples of a l l three cases are to be found i n c u r r e n t B.C. Hydro s i t u a t i o n s . Estimates f o r Hat Creek c o a l generation keep r i s i n g as more d e t a i l e d design work i s performed (the 1976$ estimate i s 64 percent higher than the 1974$ f i g u r e ; new requirements by the p r o v i n c i a l C o m p t r o l l e r of water r i g h t s w i l l r a i s e the c o s t s of the proposed Bevelstoke dam p r o j e c t ; and s t r u c t u r a l weaknesses i n the S i t e One dam on the Peace B i v e r now under c o n s t r u c t i o n w i l l c a l l f o r a d d i t i o n a l expenditures to c o r r e c t the s i t u a t i o n . 50 chosen i s a r b i t r a r y s i n c e B.C. Hydro was u n w i l l i n g to make a v a i l a b l e the necessary h i s t o r i c a l i n f o r m a t i o n to a c c u r a t e l y t e s t the s i g n i f i c a n c e of t h i s phenomenon. Annual o p e r a t i n g cost c o e f f i c i e n t s f o r v a r i o u s f a c i l i t i e s were a l s o adjusted to r e f l e c t annual r e a l l a b o u r and f o s s i l f u e l i n c r e a s e s of 2.25 and 2.0 percent r e s p e c t i v e l y . These f i g u r e s are g e n e r a l l y c o n s i s t e n t with those used by Hydro (based on r e g r e s s i o n a n a l y s i s and judgment) i n t h e i r Bevelstoke P r o j e c t B e n e f i t - C o s t A n a l y s i s (1976c). 3 7 S e v e r a l v a r i a t i o n s o f POLS1 e x i s t and are used on o c c a s i o n . POLS2 pr o v i d e s a s t a n d a r d i z e d c o n s t r u c t i o n approval date f o r a l l major p r o j e c t s so that they can be f a i r l y compared using subroutine MCOST. POLS3 co n t a i n s the approval dates f o r p r o j e c t s as given i n the 1975 Task Force Report. The use of t h i s s u broutine enables us to check on the accuracy and impact o f the endogenously c a l c u l a t e d approval dates. 4.3 DEMAND Subroutine DEMAND takes the separate net energy demand f o r e c a s t s from P0LD1, sums them t o ob t a i n t o t a l net demand, and adds t r a n s m i s s i o n l o s s e s ( c a l c u l a t e d using a c o e f f i c i e n t obtained from r e g r e s s i o n a n a l y s i s ) to achieve the gross demand that must be s u p p l i e d by the generating s t a t i o n s . The annual 3 7 T h i s study by B.C. Hydro a c t u a l l y has a base case assumption of a r e a l o i l p r i c e i n c r e a s e of 4.0 percent per year. Many a n a l y s t s now assume t h a t world o i l p r i c e s w i l l remain constant i n r e a l terms. T h i s paper uses a r a t e o f 2.0 percent but begins with the gas p r i c e s e t at the i n t e r n a t i o n a l border which, i n 1976, was s e v e r a l d o l l a r s below the BTU e g u i v a l e n t world o i l p r i c e . 51 maximum one-hour peak demand i s de r i v e d by a p p l y i n g the system load f a c t o r a n t i c i p a t e d by B.C. Hydro (63.5 percent) t o the gross demand. The equations are a l s o designed so t h a t an energy demand shock of a given magnitude can be in t r o d u c e d beginning i n a s p e c i f i e d year. A separate system l o a d f a c t o r f o r t h i s shock i s provided so th a t the peak demand may be a l t e r e d t o v a r y i n g degrees. A f i n a l secton of DEMAND in t r o d u c e s v a r i o u s p i e c e s o f f i n a n c i a l i n f o r m a t i o n f o r use l a t e r i n the model. They i n c l u d e B.C. Hydro's assumptions about the f u t u r e r a t e of i n f l a t i o n and i t s own i n t e r e s t coverage p o l i c y , as w e l l as data on i n t e r e s t payments, s i n k i n g fund d e f i c i e n c i e s and maturity dates f o r debt i s s u e d p r i o r to 1976. HJi SUPPLY Subroutine SUPPLY r e p r e s e n t s the heart of t h i s model, gen e r a t i n g the f i n a n c i a l and e n g i n e e r i n g i n f o r m a t i o n i n response to DEMAND which permits us l a t e r to perform an economic a n a l y s i s of marginal c o s t s . There are f o u r primary f u n c t i o n s o f t h i s s u b r o u t i n e . The f i r s t i s to pro v i d e the data r e g u i r e d on each o f the p o s s i b l e upstream f a c i l i t i e s (generation p r o j e c t s and t h e i r a s s o c i a t e d t r a n s m i s s i o n l i n e s ) t o perform an economic a n a l y s i s i n HCOST e n a b l i n g us to rank the p r o j e c t s i n APPROVE. Once t h i s a n a l y s i s has been done, HCOST i s bypassed and APPROVE s e t s p r o j e c t approval dates as d i c t a t e d by demand f o r e c a s t s , and the r e s u l t i n g aggregate e n g i n e e r i n g and f i n a n c i a l f i g u r e s are c a l c u l a t e d i n SUPPLY. 52 In order to o b t a i n the necessary d e t a i l r e q u i r e d f o r t h i s approach, the production c a p a b i l i t i e s and investment p r o f i l e s of over 35 d i f f e r e n t g e n e r a t i o n p r o j e c t s are m o d e l l e d . 3 8 Once t r i q q e r e d , e i t h e r by a s w i t c h when run with MCOST or by an approval date s e t i n &PPBOVE, c o n s t r u c t i o n expenditures are i n c u r r e d i n each of up to s i x years i n order t o b r i n g the p r o j e c t on stream. These expenditures are based on f i g u r e s contained i n working papers behind the 1975 Task Force Beport, updated through the a p p l i c a t i o n o f an adjustment f a c t o r s p e c i f i c to each p r o j e c t . T h i s m o d i f i c a t i o n c o n v e r t s the estimates i n t o 1976 d o l l a r s and i n c o r p o r a t e s any new r e a l c o s t changes t h a t may have been r e c o g n i z e d . 3 9 Upon p r o j e c t completion, two s t o c k s c o n t a i n i n g a d d i t i o n s to v a r i o u s c a t e g o r i e s of p l a n t i n s e r v i c e ( h y d r o - e l e c t r i c , Hat Creek c o a l , East Kootenay c o a l and gas turbine) s i n c e the s t a r t of the s i m u l a t i o n p e r i o d are augmented. The f i r s t i s measured i n 1976 d o l l a r s and i s simply the sum of the expenditures d u r i n g c o n s t r u c t i o n . I t i s used l a t e r as a base f o r determining 3 8 In the case of l a r g e p r o j e c t s with d i s t i n c t and d i v i s i b l e g e n e r a t i o n U n i t s , these U n i t s are t r e a t e d as separate p r o j e c t s whenever p o s s i b l e . 3 9 T h i s approach assumes t h a t the r e a l c o s t of c o n s t r u c t i o n f o r each p r o j e c t i s independent o f when i t i s b u i l t w i t h i n the 15 year framework we are c o n s i d e r i n g . T h i s assumption does not appear unreasonable i n l i g h t of two c o n f l i c t i n g f o r c e s at work. The f i r s t i s an observed tendency f o r c o n s t r u c t i o n c o s t s to r i s e at a s l i g h t l y higher r a t e than general p r i c e s . T h i s i n c r e a s e i n r e a l c o n s t r u c t i o n c o s t s i s o f f s e t by any t e c h n o l o g i c a l improvements which might be i n c o r p o r a t e d i n the design of f u t u r e p r o j e c t s . These are u n l i k e l y to be very l a r g e i n the case of h y d r o - e l e c t r i c f a c i l i t i e s , but may be more s i g n i f i c a n t f o r thermal p r o j e c t s . a r e c e n t study done f o r B.C. Hydro, however, i n d i c a t e d that improvements i n the e f f i c i e n c y of c o a l - f i r e d f a c i l i t i e s are expected to be no more than 10 t o 15 p e r c e n t , and these are s t i l l 10 to 15 years i n the f u t u r e . 53 o p e r a t i n g c o s t s . The second stock i s measured i n h i s t o r i c d o l l a r s (obtained by m u l t i p l y i n g each year's 1976 d o l l a r expenditure by that year's p r i c e index) and i n c l u d e s an endogenously c a l c u l a t e d i n t e r e s t during c o n s t r u c t i o n . I t w i l l serve t o help determine d e p r e c i a t i o n charges under t r a d i t i o n a l accounting procedures. I n c r e a s e s i n the stock of energy c a p a b i l i t y and of peaking c a p a c i t y f o r each category of gene r a t i n g f a c i l i t y are a l s o recorded upon p r o j e c t completion. T h i s d e t a i l e d i n f o r m a t i o n on each p r o j e c t i s then aggregated f o r a l l g e n e r a t i o n f a c i l i t i e s . These aggregated v a r i a b l e s i n c l u d e investment i n generation f a c i l i t i e s (both r e a l and nominal), energy generation c a p a b i l i t y (the e n t i r e c a p a b i l i t y f o r each category of plant under average and c r i t i c a l water c o n d i t i o n s and a t year end as w e l l as the average dur i n g the y e a r ) , peaking c a p a c i t y (the e n t i r e c a p a c i t y f o r each plant category) and value o f p l a n t i n s e r v i c e (the stock of each p l a n t category completed a f t e r 1975 i n both 1976 and h i s t o r i c d o l l a r s ) . A s i m i l a r procedure i s f o l l o w e d f o r the more than one dozen sepa r a b l e major t r a n s m i s s i o n p r o j e c t s a s s o c i a t e d with the va r i o u s g e n e r a t i o n f a c i l i t i e s . These too are t r i g g e r e d e i t h e r through a switch c o e f f i c i e n t to c o s t the genera t i o n p r o j e c t and i t s a s s o c i a t e d t r a n s m i s s i o n f a c i l i t i e s i n MCOST or through an approval date s e t i n APPROVE. The same t r a c i n g of disaggregate and aggregate economic s t o c k s and flows i s undertaken, although no e n g i n e e r i n g i n f o r m a t i o n need be maintained i n t h i s case. The second major f u n c t i o n o f s u b r o u t i n e SDPPLY i s to c a l c u l a t e the economic stoc k s and flows r e s u l t i n g from expansion 54 of downstream f a c i l i t i e s . These f a c i l i t i e s are d i v i d e d i n t o the f o l l o w i n g c l a s s i f i c a t i o n s : major t r a n s m i s s i o n l i n e s not a s s o c i a t e d with p a r t i c u l a r generation p r o j e c t s , sub- t r a n s m i s s i o n l i n e s (below 500,000 v o l t s ) , t r a n s f o r m a t i o n i n i t i a t i n g at the t r a n s m i s s i o n l e v e l , t r a n s f o r m a t i o n i n i t i a t i n g at the s u b - t r a n s m i s s i o n l e v e l , d i s t r i b u t i o n f a c i l i t i e s (below 25,000 v o l t s ) and m i s c e l l a n e o u s e l e c t r i c p l a n t . U n l i k e the upstream p r o j e c t s , investment i n these f a c i l i t i e s i s assumed t o be continuous. In most cases, expansion c o s t s are taken to be a l i n e a r f u n c t i o n of the one year lagged change i n peak demand. The r e a l c o s t c o e f f i c i e n t used i s determined on the b a s i s of a n a l y s i s of past c o n s t a n t d o l l a r expenditures and/or d i s c u s s i o n with the a p p r o p r i a t e o f f i c i a l s about present and expected c o s t s . * o Investment i n d i s t r i b u t i o n f a c i l i t i e s has been s p l i t .between that r e g u i r e d to serve new customers (which i s taken to be a l i n e a r f u n c t i o n of the one year lagged change i n the number of customers) and t h a t prompted by growth i n the peak demands of e x i s t i n g customers. Investment i n miscellaneous e l e c t r i c p l a n t , a r e l a t i v e l y minor item, i s assumed to be a l i n e a r f u n c t i o n of the one year lagged change i n annual energy demand. The investment i n each type of f a c i l i t y i s accumulated i n separate s t o c k s of new p l a n t i n s e r v i c e measured i n both 1976 and h i s t o r i c d o l l a r s . S t i l l i n the system design area, a t h i r d r e s p o n s i b i l i t y of •o The a n a l y s i s of expenditures on f a c i l i t i e s below the major t r a n s m i s s i o n l e v e l can be d i f f i c u l t due t o problems i n o b t a i n i n g and a l l o c a t i n g the a p p r o p r i a t e l y disaggregated c o s t i n f o r m a t i o n . T h i s problem i s l a r g e l y avoided i n t h i s paper by a n a l y z i n g o n l y the very l a r g e s t customers (who take e l e c t r i c i t y at the sub- t r a n s m i s s i o n l e v e l ) and the very s m a l l e s t customers (who r e g u i r e , i n a d d i t i o n , a l l the downstream f a c i l i t i e s ) . 55 SUPPLY i s to determine the d e s i r e d r e s e r v e margin of peaking c a p a c i t y over peak demand. T h i s depends l a r g e l y on the nature of the generating system with c o a l - f i r e d u n i t s r e q u i r i n g a g r e a t e r margin than the more dependable h y d r o - e l e c t r i c f a c i l i t i e s . Once the ranking of new p r o j e c t s has been determined, the d e s i r e d reserve margin i s s p e c i f i e d as a f u n c t i o n of the peaking c a p a c i t y of v a r i o u s types of generating equipment. The f o u r t h major task o f t h i s s u b r o u t i n e i s to determine the q u a n t i t y and source of energy qenerated each year. T h i s i s achieved by u t i l i z i n g g e n e r a t i n g f a c i l i t i e s i n order of i n c r e a s i n g o p e r a t i n g c o s t s u n t i l gross demand i s met. Thus, h y d r o - e l e c t r i c g e n e r a t i n g p l a n t s f i r s t meet demand, f o l l o w e d by c o a l and then p e t r o l e u m - f i r e d U n i t s . Any remaining energy d e f i c i t s are s u p p l i e d by imports, although the system i s designed so that these w i l l not be r e q u i r e d {because the demand, i n the runs r e p o r t e d here, i s assumed to be known s i x years i n advance). Gross demand i s t h a t generated i n DEMAND p l u s the a v a i l a b l e export demand t h a t i s economic to s e r v e . B.C. Hydro i s assumed to seek t o export the d i f f e r e n c e between t o t a l energy c a p a b i l i t y {under whatever water c o n d i t i o n s are s p e c i f i e d ) and gross f i r m energy demand whenever the marginal o p e r a t i n g c o s t s to s o c i e t y are below the marginal revenue that would be r e c e i v e d . A c o e f f i c i e n t with a base case value of .5 i n d i c a t e s what p r o p o r t i o n of the export market sought i s a c t u a l l y a t t a i n e d . 56 JK5 MCOST Subroutine HCOST takes the data from SUPPLY and performs an economic a n a l y s i s of both the c o s t o f the major gener a t i o n p r o j e c t s with t h e i r a s s o c i a t e d t r a n s m i s s i o n f a c i l i t i e s and the cos t of each p r o j e c t ' s s e p a r a b l e U n i t s . 4 1 Each year during a p r o j e c t ' s l i f e , r e a l o p e r a t i n g , d e p r e c i a t i o n and c a p i t a l c o s t s are determined. These average annual c o s t s are a d j u s t e d upward s l i g h t l y t o transform them to an end of year p o s i t i o n and are then accumulated i n a stock v a r i a b l e which i s compounded forward each year by the r e a l r a t e of s o c i a l time p r e f e r e n c e . Upon the p r o j e c t ' s t e r m i n a t i o n , t h i s s t o c k i s d i v i d e d by the r e a l s o c i a l time preference r a t e r a i s e d to a power r e f l e c t i n g the number of years elapsed s i n c e 1976. T h i s serves to d i s c o u n t c o s t s back t o y i e l d a present value of r e a l c o s t s as viewed from 1976. Depicted a l g e b r a i c a l l y , each year f o l l o w i n g p r o j e c t i ' s app r o v a l , K C i , t = KCi,t-1 * (1 + STP) + C i , t * <1 + STP)**.5 .,...(1) Upon t e r m i n a t i o n of p r o j e c t i , KCPVi = K C i , t / (1 + STP) **n (2) where: KCi,t i s the stock o f accumulated r e a l c o s t s a s s o c i a t e d with p r o j e c t i i n year t ; 4 1 The Hevelstoke p r o j e c t , f o r example, has s i x gen e r a t i o n U n i t s which can be developed at d i f f e r e n t times. 57 STP i s the r e a l rate of s o c i a l time preference (with a base case value of .05); C i , t are the r e a l operating, depreciation and c a p i t a l costs associated with project i i n year t; KCPVi i s the discounted present value of a l l r e a l costs over project i ' s l i f e ; n i s the number of years elapsed since 1976. In order to be able to compare and rank the different projects, these costs must be divided by a measure of e l e c t r i c a l output. We use the incremental energy c a p a b i l i t y (under average water conditions) for the major projects, and peaking capacity for those which are not designed to generate energy. A s i m i l a r annual compounding and f i n a l discounting procedure to that set out above i s followed. As both the costs and output associated with each complete project depend upon the rate of development of the project's separable Units and t h e i r interaction with the system's other generation sources,* 2 a base case must be sp e c i f i e d . In t h i s paper, we use the rate of development and interdependence of projects recommended in the 1975 Task Force Report. Subroutine POLS2 i s used to set a standard i n i t i a l approval date of 1975 for each major project. There are three components to the operating costs associated with generation and transmission projects. Following the 1975 Task Force Report, fixed r e a l annual operating costs * 2 This i s p a r t i c u l a r l y true for hydro-electric projects. For example, the e f f e c t on net output of a r i v e r diversion depends on the generating f a c i l i t i e s on both r i v e r s affected by the diversion. 58 are taken to be a c a t e g o r y - s p e c i f i c percentage of the t o t a l r e a l c a p i t a l c o s t of each p r o j e c t . The only m o d i f i c a t i o n to t h i s approach i n t r o d u c e d i n t h i s paper i s the p r e v i o u s l y d e s c r i b e d i n c o r p o r a t i o n of r e a l wage i n c r e a s e s which r e s u l t s i n the i n c r e a s e of t h i s c o e f f i c i e n t over time. We a l s o use the f i g u r e s (updated to 1976 d o l l a r s ) suggested i n the 19 75 Report f o r the non-fuel v a r i a b l e c o s t s i n m i l l s per KWH . We do depart, however, from the Task Force i n our s e l e c t i o n of some of the v a r i a b l e c o s t s of f u e l . The o p p o r t u n i t y p r i c e of n a t u r a l gas at the Burrard p l a n t i s taken to be $1.83 per thousand cub i c f e e t (Mcf) (18.3 m i l l s per KWH ), approximately t r i p l e what B.C. Hydro was a c t u a l l y paying i n 1976. T h i s i s based on a s m a l l net upward adjustment, due t o t r a n s p o r t a t i o n c o s t s , 4 3 of the export p r i c e of $1.80 per Mcf at the Canada- U.S. border near Vancouver, and i s e q u i v a l e n t t o an o i l p r i c e of $11.00 a b a r r e l . The estimated average f u e l c o s t at a l l gas t u r b i n e p l a n t s i s assumed to be 28 m i l l s per KWH. Hat creek c o a l i s valued at $6.00 per ton, l e s s than one- t h i r d more than the r e v i s e d c o s t to B.C. Hydro of e x t r a c t i n g the c o a l and paying the p r o v i n c i a l r o y a l i t y . 4 4 T h i s f i g u r e i s l e s s than 25 percent g r e a t e r than the A u t h o r i t y ' s "most l i k e l y " o p p o r t u n i t y value of the c o a l , and w e l l below the more than * 3 The d i s t a n c e of the B.C. Hydro gas t r a n s m i s s i o n l i n e from the Westcoast p i p e l i n e (the wholesaler) to the Burrard p l a n t i s g r e a t e r than the d i s t a n c e from the B.C. Hydro tap to the Canada- U.S. Border. 4 4 T h i s higher c o a l c o s t r e f l e c t s the o p p o r t u n i t y c o s t concept employed i n t h i s paper. However, i t s use may not be u n r e a l i s t i c i n l i g h t of the p o s s i b i l i t y t h a t the Province may r a i s e i t s c o a l r o y a l t y to capture t h i s economic r e n t . A l t e r n a t i v e l y , t h i s adjustment could be viewed as i n c o r p o r a t i n g some of the e x t e r n a l c o s t s a s s o c i a t e d with c o a l use. 59 $10.00 p r i c e t h a t has been suggested by the B.C. Energy Commission (B.C.E.C., 1975). The higher g u a l i t y East Kootenay open p i t c o a l , about which r e l a t i v e l y l i t t l e i s known, i s valued at $12.00 per ton, some o n e - t h i r d above the c o s t of e x t r a c t i o n ( i n c l u d i n g r o y a l t i e s at e x i s t i n g rates) used by the 1975 Task Force Report. Water l i c e n c e f e e s are assumed t o r e p r e s e n t the o p p o r t u n i t y c o s t of the use o f the r i v e r and are l e f t a t the 1976 a c t u a l r a t e s . * 5 As mentioned e a r l i e r , the r e a l p r i c e of o i l , n a t u r a l gas and c o a l i s assumed with the r e s u l t t h a t the petroleum f u e l s r i s e at two percent a n n u a l l y to reach a 1976$ o i l p r i c e e q u i v a l e n t of $14.50 i n 1990. Three types of d e p r e c i a t i o n charges are used i n performing the economic a n a l y s i s of the v a r i o u s p r o j e c t s . The base case employs the " o p p o r t u n i t y l i f e " s t r a i g h t l i n e method using an average expected s e r v i c e l i f e of 40 y e a r s . T h i s f i g u r e i s d e r i v e d by weighting the expected economic l i f e of d i f f e r e n t c l a s s i f i c a t i o n s of n o n - r e s i d e n t i a l c a p i t a l s t o c k i n Canada by t h e i r mid-1976 net c o n s t a n t d o l l a r s t o c k . * 6 For comparison, we a l s o use the t r a d i t i o n a l s t r a i g h t l i n e d e p r e c i a t i o n on the expected l i f e of the p r o j e c t and a 5.7 percent annual charge a p p l i e d to a d e c l i n i n g balance measure of net c a p i t a l s t o c k . T h i s l a t t e r approach i s t h a t used i n the Bank o f Canada's RDX2 model of the Canadian economy and i s simply a d i f f e r e n t * 5 T h i s assumption i s c l e a r l y not a p p r o p r i a t e f o r a l l of B.C. Hydro's present and p r o s p e c t i v e dam s i t e s . However, the A u t h o r i t y ' s f i g u r e s suggest t h a t the o p p o r t u n i t y c o s t of t h e a f f e c t e d r i v e r s i s g e n e r a l l y r e l a t i v e l y s m a l l . * 6 T h i s f i g u r e was c a l c u l a t e d from i n f o r m a t i o n c o n t a i n e d i n S t a t i s t i c s Canada's Fixed C a p i t a l Flows and Stocks, 1972-76. 60 a p p l i c a t i o n of t h e "o p p o r t u n i t y l i f e " concept. In a l l cases, the d e p r e c i a t i o n charge i s a p p l i e d t o the previous year*s net c a p i t a l stock p l u s new investment measured i n r e a l terms. A l g e b r a i c a l l y , Dt = D * (Kt-1 • It) ........^..........................(3) where: Kt = (Kt-1 + It) * (1 - D) ; Dt i s the r e a l d e p r e c i a t i o n charge i n year t; Kt i s the net r e a l c a p i t a l stock i n year t ; I t i s the r e a l investment i n year t ; D i s the r e l e v a n t d e p r e c i a t i o n r a t e . Following the o p p o r t u n i t y cost concept, the annual c o s t of c a p i t a l c o n s i s t s of two components. The f i r s t i s the a f t e r - t a x r e a l supply p r i c e of c a p i t a l to business of 7.5 percent as used i n the RDX2 model. The second i s the RDX2 average r e a l annual tax r e t u r n on i n d u s t r i a l c a p i t a l of 3.0 percent. The t o t a l of 10.5 percent i s a p p l i e d t o the average net stock of c a p i t a l each y e a r . * 7 The r e a l r a t e o f s o c i a l time p r e f e r e n c e i s taken t o be 5.0 percent, h a l f t h a t g e n e r a l l y used by B.C. Hydro. T h i s f i g u r e may s t i l l be somewhat hig h , given t h a t the r e a l r e t u r n on government bonds, a reasonable proxy, has averaged 3 to 4 percent i n the p a s t . * 8 S e n s i t i v i t y a n a l y s i s i s performed using r e a l r a t e s o f * 7 T h i s approach i s s i m i l a r to t h a t used i n H e l l i w e l l et a l (1976) . *« See Campbell (1975). 61 2.5 and 7.5 percent. To summarize t h i s e x p l a n a t i o n of the d e t e r m i n a t i o n of the r e a l annual c o s t s a s s o c i a t e d with each p r o j e c t , we present a l g e b r a i c a l l y the components of the C i , t shown i n equation (1). C i , t = & i , t * KGi,t + B i , t * Q i , t + D i , t * (Ki,t-1 + I i , t ) • E * ( K i , t - 1 «• K i , t ) / 2 ..{4) where: C i , t are the r e a l o p e r a t i n g , d e p r e c i a t i o n and c a p i t a l c o s t s a s s o c i a t e d with p r o j e c t i i n year t as per e q u a t i o n (1); A i , t i s the f i x e d r e a l annual o p e r a t i n q c o s t c o e f f i c i e n t f o r p r o j e c t i i n year t ; KGi,t i s the accumulated r e a l c a p i t a l c o s t of p r o j e c t i i n year t ( p r o j e c t i * s qross r e a l c a p i t a l s t o c k ) ; B i , t i s the v a r i a b l e ( f u e l and non-fuel) annual r e a l o p e r a t i n q c o s t c o e f f i c i e n t f o r p r o j e c t i i n year t ; Q i , t i s the e l e c t r i c a l output ( i n KHH) of p r o j e c t i i n year t ; D i , t i s the c o e f f i c i e n t r e f l e c t i n q the type o f d e p r e c i a t i o n method being employed on p r o j e c t i i n year t ; K i , t i s the net r e a l c a p i t a l s t o c k a s s o c i a t e d with p r o j e c t i i n year t ; I i , t i s the r e a l investment i n p r o j e c t i i n year t ; E i s the c o e f f i c i e n t r e f l e c t i n g the b e f o r e - t a x r e a l supply p r i c e o f c a p i t a l (assumed to be .105). 62 JH-6 AREEQ.11 T h i s s u b r o u t i n e operates i n a time h o r i z o n s i x years ahead of the p e r i o d being s i m u l a t e d and approves new generation and tr a n s m i s s i o n p r o j e c t s when f u t u r e energy c a p a b i l i t y and/or peaking c a p a c i t y i s expected to f a l l s h o r t of f u t u r e energy and/or peak demand. Future gross demand, i n c l u d i n g any demand shocks, i s c a l c u l a t e d i n su b r o u t i n e DEMAND using the i n f o r m a t i o n obtained i n P0LD1.. Future energy and peaking c a p a c i t y i s determined on the b a s i s o f e x i s t i n g and approved g e n e r a t i o n p r o j e c t s . When a d e f i c i e n c y i n e i t h e r component i s f o r e c a s t , the next l e a s t - c o s t p r o j e c t (based on r e s u l t s obtained from MCOST ) that can f i l l the gap i s approved, and supply c a p a b i l i t y and c a p a c i t y s i x years hence are a p p r o p r i a t e l y augmented. The t e c h n i c a l c r i t e r i a used to determine f u t u r e d e f i c i e n c e s are those now i n use by B.C. Hydro as e x p l a i n e d i n Chapter 2. P r o j e c t s are approved o n l y i f the t e c h n i c a l , l e g a l and environmental r e s t r i c t i o n s mentioned i n t h a t chapter have been met. Those p r o j e c t s r e q u i r i n g fewer than s i x c o n s t r u c t i o n years are approved i n time f o r them t o come on stream i n the s i x t h year. S p e c i a l c o n s i d e r a t i o n i s given t o the need f o r gas t u r b i n e s on Vancouver I s l a n d to supply l o c a l peak demand because of l i m i t a t i o n s on underwater t r a n s m i s s i o n c a p a c i t y . The s u b r o u t i n e does not f u l l y o p t i m i z e a p p r o v a l dates on the b a s i s of economic c r i t e r i a because o f the complexity t h a t Mould be i n v o l v e d . * 9 However, the ra n k i n g and a p p r o v a l c o n d i t i o n s are s e t so as to r e c o g n i z e and i n c o r p o r a t e economic c o n s i d e r a t i o n s as much as p o s s i b l e . P r o j e c t s are ranked i n order of i n c r e a s i n g c o s t f o r t h e i r complete development. R e l a t i v e l y low c o s t d i v e r s i o n p r o j e c t s are given p r i o r i t y once they are t e c h n i c a l l y f e a s i b l e . , The i n e x p e n s i v e "middle U n i t s " of major hydro p r o j e c t s are brought on g u i c k l y so as to d i s p l a c e e x i s t i n g high c o s t thermal s o u r c e s . 5 0 In s h o r t , an attempt i s made to approximate the economically o p t i m a l timing of new p r o j e c t s s u b j e c t to the t e c h n i c a l c r i t e r i a t h a t must be met. s l 4.7 COSTS T h i s s u b r o u t i n e performs two major f u n c t i o n s . The f i r s t i s to determine annual c o s t s a c c o r d i n g to t r a d i t i o n a l accounting procedures. These c o s t s are c a l c u l a t e d each year i n terms of nominal d o l l a r s and are then converted i n t o 1976 d o l l a r s and * 9 In order t o determine the o p t i m a l economic t i m i n g of a new, r e l a t i v e l y l a r g e p r o j e c t which would d i s p l a c e a c u r r e n t high c o s t marginal source, one would r e q u i r e i n f o r m a t i o n about the expected f u t u r e qrowth r a t e i n demand, the r a t e of development of the d i f f e r e n t U n i t s of the new p r o j e c t and the v a r i a n c e of s e v e r a l key parameters. R e l i a n c e s o l e l y on the t e c h n i c a l c r i t e r i a , however, i n t r o d u c e s d i s c o n t i n u i t i e s i n the c o s t curves as minor q u a n t i t y chanqes can have major c o s t i m p l i c a t i o n s . These i n s t a b i l i t i e s would be reduced with a f u l l economic a n a l y s i s which c o n s i d e r e d the c o s t s and b e n e f i t s of proceedinq with or d e f e r r i n q a new p r o j e c t . s 0 The i n i t i a l U n i t s of a l a r q e h y d r o - e l e c t r i c p r o j e c t are expensive because of the hiqh c o s t s a s s o c i a t e d with r e s e r v o i r and dam c o n s t r u c t i o n . The i n c r e m e n t a l c o s t s of the "middle U n i t s " are r e l a t i v e l y low compared with the a d d i t i o n a l energy that w i l l be provided. The f i n a l U n i t s , however, produce l i t t l e new energy and thus show higher c o s t s per u n i t of output. 5 1 I f r e q u i r e d , the approval dates suqqested by the model could be manually adjusted to f i n d the p r e c i s e plan which minimized the present v a l u e of c o s t s s u b j e c t to the s a t i s f a c t i o n o f a l l t e c h n i c a l c r i t e r i a . 64 d i v i d e d by gross energy p r o d u c t i o n to get r e a l cost per KWH as measured by the accountant. Fixed o p e r a t i n g c o s t s are i n i t i a l l y s e t at t h e i r 1975 l e v e l and are l a t e r i n c r e a s e d by a p p l y i n g v a r i o u s p r i c e - a d j u s t e d c o e f f i c i e n t s t o d i f f e r e n t c a t e g o r i e s of new p l a n t i n s e r v i c e (as measured i n 1976 d o l l a r s ) . V a r i a b l e o p e r a t i n g c o s t s are determined through the a p p l i c a t i o n of p r i c e - a d j u s t e d c o e f f i c i e n t s to the g e n e r a t i n g sources a c t u a l l y u s e d . 5 2 Water l i c e n c e f e e s , s c h o o l taxes, municipal 'grants' and l a n d taxes are c a l c u l a t e d using the procedures now i n e f f e c t i n B.C. D e p r e c i a t i o n charges are f i r s t s e t a t t h e i r 1975 amount and are subsequently augmented by the product of a c o e f f i c i e n t r e p r e s e n t i n g the i n v e r s e of the expected economic l i f e of new p r o j e c t s and the new p l a n t i n s e r v i c e (as measured i n h i s t o r i c d o l l a r s ) . New bonds are i s s u e d to make up the d i f f e r e n c e between t o t a l f i n a n c i a l requirements ( i n c l u d i n q s i n k i n g fund c o n t r i b u t i o n s and s h o r t f a l l s i n repayment of p r i n c i p a l a t maturity) and what can be generated i n t e r n a l l y under the new f i n a n c i a l p o l i c y on d e s i r e d net income l e v e l s . I n t e r e s t payments are then determined on the b a s i s of these new o u t s t a n d i n g bonds as w e l l as the commitments on bonds i s s u e d before 1976. The second f u n c t i o n of t h i s s u b r o u t i n e i s to perform an economic a n a l y s i s of the change i n c o s t s a s s o c i a t e d with the demand shock i n t r o d u c e d e a r l i e r . The a n a l y s i s f o l l o w s the same bas i c procedures as were used i n comparing p o s s i b l e p r o j e c t s i n S 2 In order t o be c o n s i s t e n t with c o s t s used i n the economic a n a l y s i s , and because r o y a l t i e s may be i n c r e a s e d t o c o r r e c t the c u r r e n t s i t u a t i o n , the o p p o r t u n i t y (rather than a c t u a l ) c o s t of the v a r i o u s f u e l s i s employed i n the accounting s e c t i o n . 65 MCOST. T h i s time, however, we are i n t e r e s t e d i n the system as a whole, and wish to examine the impact on those c o s t s with a p o s i t i v e o p p o r t u n i t y v a l u e - a l l v a r i a b l e and any new f i x e d charges. We a l s o wish to d i s t i n g u i s h between the c o s t s i n c u r r e d by the s m a l l e s t and l a r g e s t customers. The v a r i o u s generating and downstream f a c i l i t i e s are grouped i n t o d i f f e r e n t c a t e g o r i e s of r e l a t i v e l y homogeneous a s s e t s . F i x e d o p e r a t i n g cost c o e f f i c i e n t s are a p p l i e d t o each category's post-1975 gross r e a l c a p i t a l s t o c k while v a r i a b l e o p e r a t i n g o p p o r t u n i t y c o s t c o e f f i c i e n t s are a p p l i e d , where a p p r o p r i a t e , to the t o t a l g u a n t i t y produced by each a s s e t category. Annual d e p r e c i a t i o n charges are c a l c u l a t e d using the economy-wide average r a t e o f 5.7 percent taken on a d e c l i n i n g balance measure of post-1975 c a p i t a l s tock. The c o s t of c a p i t a l i s determined using the before-tax r e a l s upply p r i c e of 10.5 percent a p p l i e d to the average net r e a l post-1975 c a p i t a l s t o c k . By summing acr o s s a l l a s s e t c a t e g o r i e s the c o s t s a s s o c i a t e d with the s m a l l e s t customers are determined while the l a r g e s t customers r e q u i r e o n l y those c a t e g o r i e s down to the sub- t r a n s m i s s i o n l e v e l . These c o s t s are compounded forward a n n u a l l y , as are the r e l e v a n t q u a n t i t i e s , to the end of the s i m u l a t i o n p e r i o d and are then discounted back t o 1976, again using the r e a l r a t e of s o c i a l time p r e f e r e n c e . A s i m u l a t i o n p e r i o d of 55 years i s used i n t h i s i n s t a n c e to represent an average l i f e f o r new f a c i l i t i e s brought on stream between 1975 and 1990. By comparing the change i n the discounted present value of c o s t s between the base case run and one c o n t a i n i n g a demand shock, with the corresponding 66 change i n the q u a n t i t y s u p p l i e d , a marginal c o s t per u n i t of output can be a t t a i n e d . The procedures f o l l o w e d f o r the economic a n a l y s i s are h i g h l i g h t e d a l g e b r a i c a l l y below. For each a s s e t category j i n each year t , C j , t = Aj#t * KGj,t + B j , t * Q j , t * D * (Kj,t-1 * I I , t ) + E * <Kj,t-1 + K j , t ) / 2 ..(5) where: C j , t are the r e a l o p e r a t i n g , d e p r e c i a t i o n and c a p i t a l o p p o r t u n i t y c o s t s a s s o c i a t e d with a s s e t category j i n year t ; A j , t i s the f i x e d r e a l annual o p e r a t i n g c o s t c o e f f i c i e n t f o r category j i n year t ; KGj,t i s category j * s post-1975 gross r e a l c a p i t a l stock i n year t ; B j , t i s the v a r i a b l e { f u e l and non-fuel) annual r e a l o p e r a t i n g c o s t c o e f f i c i e n t f o r c a t e g o r y j i n year t ; Q j , t i s the e l e c t r i c a l output {in KWH) produced by category j i n year t ; D i s the d e p r e c i a t i o n charge c o e f f i c i e n t of .057; K j , t i s category j»s post-1975 net r e a l c a p i t a l stock i n year t ; I j , t i s the r e a l investment i n category j i n year t ; E i s the before-tax r e a l supply p r i c e of c a p i t a l c o e f f i c i e n t of .105. For customer c l a s s k, x Ck,t = C j , t t = 1,...,55 ... ....{ where: x i s the number o f a s s e t c a t e g o r i e s r e q u i r e d to serve customer c l a s s k. Each year during the s i m u l a t i o n p e r i o d , KCk,t = KCk,t-1 * (1 + STP) + Ck,t * (1 • STP)**.5 . . - . . ( and KQk,t = KQk,t-1 * (1 + STP) + Qk,t * (1 + STP)**.5 { where: KCk,t i s the stock of accumulated r e a l c o s t s a s s o c i a t e d with customer c l a s s k i n year t ; STP i s the r e a l r a t e of s o c i a l time p r e f e r e n c e (with a base case value of .05); KQk,t i s the stock o f accumulated gross p r o d u c t i o n a s s o c i a t e d with s u p p l y i n g customer c l a s s k i n year t Qk,t i s the gross production (in KWH) a s s o c i a t e d with s u p p l y i n g customer c l a s s k i n year t . 68 At the end of the s i m u l a t i o n p e r i o d . KCPVk = KCk, t / (1 + STP) **n (9) and KQPVk = KQk,t / {1 + STP)**n (10) where: KCPVk i s the discounted present value of a l l r e a l o p p o r t u n i t y c o s t s a s s o c i a t e d with s u p p l y i n g customer c l a s s k during the s i m u l a t i o n p e r i o d ; KQPVk i s the discounted present value of a l l gross production a s s o c i a t e d with s u p p l y i n g customer c l a s s k during the s i m u l a t i o n p e r i o d ; n i s the number o f years between the end of 1976 and the end of the s i m u l a t i o n p e r i o d (53). The marginal c o s t per u n i t o f output f o r customer c l a s s k (KCPVk,base - KCPVk,shock) / where: the s u b s c r i p t s base and shock i n d i c a t e the value of these v a r i a b l e s under base case and demand shock c o n d i t i o n s , r e s p e c t i v e l y . (KQPVk,base - KQPVk,shock) (11) 69 kJL RATES T h i s s u b r o u t i n e provides an i n d i c a t i o n o f f u t u r e r e a l and nominal average e l e c t r i c i t y p r i c e s f o r v a r i o u s customer c l a s s e s using the i n f o r m a t i o n from the c o n v e n t i o n a l accounting s e c t i o n of COSTS. Revenues from r e s i d e n t i a l , g e n e r a l , bulk, p r i v a t e u t i l i t y and export s a l e s are c a l c u l a t e d based on e x i s t i n g and committed average p r i c e s and f o r e c a s t s a l e s . Any a n t i c i p a t e d d i f f e r e n c e s between the nominal revenue t h a t w i l l be generated and that r e g u i r e d to meet t o t a l nominal c o s t s w i l l be e l i m i n a t e d by an adjustment i n average p r i c e s . T h i s adjustment i s the same percentage change f o r a l l c l a s s e s (except f o r the export p r i c e which i s hel d c o n s t a n t i n r e a l terms) and assumes a zero demand response to the changed p r i c e s . For the a p p l i c a t i o n s chapter of t h i s paper, the model w i l l be extended so as to permit a p p r o p r i a t e demand responses to the new marginal p r i c e s t h a t w i l l be i n c o r p o r a t e d i n the r e v i s e d rate s t r u c t u r e . 70 5jt THE RESULTS In t h i s chapter se present the r e s u l t s of computer s i m u l a t i o n runs using the model t h a t has j u s t been o u t l i n e d . The f i r s t s e c t i o n r e p o r t s on the p r o j e c t c o s t i n g and r a n k i n g f u n c t i o n ; the second f o r e c a s t s c o s t s using a c o n v e n t i o n a l accounting approach; and the t h i r d presents v a r i o u s e s t i m a t e s of marginal economic c o s t s . A l l t h r e e s e c t i o n s p rovide the r e s u l t s of s e n s i t i v i t y a n a l y s e s i n which key assumptions are a l t e r e d from those i n the base case, as w e l l as attempt an i n t e r p r e t a t i o n of the r e s u l t s obtained. 5.1 P r o j e c t C o s t i n g And Ranking 5.1.1 Base Case The r e s u l t s of the p r o j e c t c o s t i n g a n a l y s i s performed i n s u b r o u t i n e MCOST are presented i n T a b l e 1. Generation p r o j e c t s are grouped a c c o r d i n g to whether they are heing c o n s i d e r e d p r i m a r i l y f o r t h e i r c o n t r i b u t i o n to energy c a p a b i l i t y or peaking c a p a c i t y . They are ranked w i t h i n each category i n the order of i n - s e r v i c e dates as proposed i n the 1975 Task f o r c e Report. These dates i n d i c a t e when e x i s t i n g t e c h n i c a l , l e g a l , environmental and/or s o c i a l c o n s t r a i n t s are expected to be overcome. With the exception of the Hat Creek and East Kootenay c o a l - f i r e d p l a n t s and the gas t u r b i n e s proposed f o r Vancouver I s l a n d , a l l p r o j e c t s a r e . h y d r o - e l e c t r i c . Three key assumptions used i n generating the base case r e s u l t s are that r e a l c a p i t a l c o s t s exceed present estimates by TABLE 1 COSTING OF GENERATION PROJECTS ENERGY PROJECTS (1) UNIT NO. (2) EARLIEST POSSIBLE (3) AVERAGE ENERGY IN-SERVICE CAPABILITY DATE (MM KWH) (4) PEAKING CAPACITY (M W) (5) BASE CASE SITE ONE (now under const.) REVEL-STOKE HAT CREEK I KOOTENAY DIVERSION MCGREGOR DIVERSION (assumes Site C) HAT CREEK II EAST KOOTENAY 1-4 1-6 1-4 1 1 5-8 1-2 SITE C (without McGregor Div.) 1-4 CAPACITY PROJECTS VANCOUVER ISLAND GAS TURBINES G.M. SHEDM MICA MICA EEVELSTOKE REVELSTOKE SEVEN MILE 1-2 10 5 6 5 6 4 1979 1981 1982 1984 1985 1985 1983 1984 3150 7970 13,680 875 3828 19,160 9580 4290 1314 700 2700 2000 75 2800 1400 900 300 275 400 400 450 450 175 13 14 19 2 7 18 17 19 ($/KW) 206 10 7 7 11 10 15 ( 6) (?) (8) (9) (10) (11) CAPITAL STP DEPRECIATION' COST ! NO 50% CONVENTIONAL DECLINING COST COST 2.5% 7.5% STRAIGHT "E"AL4*CE OVERRUN OVERRUN ' LINE METHOD- 11 • 16 11 16 15 13 12 17 11 17 16 14 17 21 19 20 19 19 2 3 2 3 2 2 6 .8 6 8 S 7 16 20 18 18 IS 18 16 IS 17 17 17 17 16 22 15 22 21 19 201 212 214 199 206 204 8 12 8 12 11 10 6 8 6 8 8 7 6 8 6 8 7 7 9 13 & 12 12 10 8 12 S 11 11 10 12 18 12 17 16 14 72 25 percent, t h a t the r e a l r a t e of s o c i a l time p r e f e r e n c e i s 5.0 percent and that t h e s t r a i g h t l i n e " o p p o r t u n i t y l i f e " d e p r e c i a t i o n method i s the a p p r o p r i a t e technigue to use. To put the numbers i n the t a b l e i n p e r s p e c t i v e , the o p e r a t i n g cost of the Burrard thermal p l a n t {with n a t u r a l gas p r i c e d at i t s o p p o r t u n i t y value) i s 19 m i l l s per KWH. The s i m i l a r i t y i n c o s t between the S i t e C hydro p r o j e c t and the Hat Creek c o a l - f i r e d p l a n t should be noted at t h i s stage. A f u r t h e r a n a l y s i s under base case assumptions was performed on the c o s t s a s s o c i a t e d with the separable U n i t s comprising each major g e n e r a t i o n p r o j e c t . As would be expected, these c o s t s per u n i t of output i n i t i a l l y f a l l and then o f t e n turn upwards as the p r o j e c t i s more f u l l y developed. Thus f o r the Sevelstoke p r o j e c t with i t s f u l l y developed c o s t s of 14 m i l l s per KWH, U n i t s 1 and 2 together show a c o s t of 16 m i l l s while U n i t s 3 and 4, based on the i n c r e m e n t a l c o s t s and production that each i s r e s p o n s i b l e f o r , are c o s t e d at 3 and 8 m i l l s r e s p e c t i v e l y . U n i t s 5 and 6 add only to peaking c a p a c i t y . T h i s i n f o r m a t i o n i s l a t e r used to suggest the a p p r o p r i a t e r a t e of development of each p r o j e c t . We t u r n now to examine the impact on a b s o l u t e and r e l a t i v e per u n i t economic c o s t r e s u l t i n g from a change i n each o f the three key assumptions l i s t e d i n the l a s t paragraph. 5.1.2 S e n s i t i v i t y A n a l y s i s Columns 6 and 7 of Table 1 r e v e a l the r e s u l t s of " a c r o s s the board" c a p i t a l c o s t adjustments of z e r o and f i f t y percent 73 r e s p e c t i v e l y . 5 3 The changes w i l l a f f e c t f i x e d o p e r a t i n g c o s t s (which are determined by a p p l y i n g a c o e f f i c i e n t t o each p r o j e c t ' s c a p i t a l c o s t ) but w i l l leave unchanged v a r i a b l e o p e r a t i n g c o s t s . I t i s not s u r p r i s i n g then t h a t these v a r i a t i o n s have a strong impact on the u n i t c o s t s of a l l p r o j e c t s , although the e f f e c t i s s m a l l e r with the c o a l - f i r e d p r o j e c t s . Indeed t h i s d i f f e r e n t i a l impact i s c r i t i c a l i n determining whether the S i t e C p r o j e c t should proceed before a p l a n t at Hat Creek. The next columns i n d i c a t e the impact of v a r y i n g the r e a l r a t e of s o c i a l time p r e f e r e n c e (STP) from 5.0 percent to 2.5 and 7.5 percent, a higher STP r a t e i m p l i e s a g r e a t e r d i s c o u n t i n g o f the f u t u r e r e l a t i v e to the present. Because of the d e c l i n i n g r e a l c o s t s over time charged t o each p r o j e c t , a higher STP r a t e w i l l cause a grea t e r r e d u c t i o n i n the present value of the q u a n t i t y produced (which i s assumed t o be con s t a n t through the p r o j e c t ' s l i f e ) than i n the c o s t s of p r o d u c t i o n . T h i s w i l l l e a d to h i g h e r di s c o u n t e d u n i t c o s t s . The opp o s i t e a p p l i e s i n the case of a reduced STP r a t e . He again see the d i f f e r e n t i a l impact of these changes, with the c a p i t a l i n t e n s i v e hydro p r o j e c t s being the more s e n s i t i v e to t h i s v a r i a t i o n . The ra n k i n g o f the S i t e C and Hat Creek p r o j e c t s i s even more dependent on t h i s v a r i a b l e than on the c a p i t a l c o s t assumption. The f i n a l cclumns i n Table 1 show the e f f e c t o f the d i f f e r e n t d e p r e c i a t i o n procedures d i s c u s s e d i n the l a s t chapter. 5 3 a b e t t e r approach would be to choose p o s s i b l e c a p i t a l c o s t v a r i a t i o n s on the b a s i s of present knowledge and experience f o r each p r o j e c t . Thus the c a p i t a l c o s t estimate of a r e l a t i v e l y standard design hydro p r o j e c t on a w e l l surveyed s i t e would l i k e l y be more a c c u r a t e than that o f the f i r s t c o a l - ^ f i r e d p l a n t ever to be b u i l t by B.C. Hydro. 74 Standard s t r a i g h t l i n e d e p r e c i a t i o n based on the a s s e t ' s expected l i f e y i e l d s a higher u n i t c o s t f o r p r o j e c t s with a l i f e g r e a t e r than the economy-wide average (such as h y d r o - e l e c t r i c f a c i l i t i e s ) . although the annual d e p r e c i a t i o n charges are lower under the c o n v e n t i o n a l method f o r the l o n g - l i v e d a s s e t s , the c o s t of c a p i t a l i s high e r s i n c e i t i s a p p l i e d to a net stock which i s not d e c l i n i n g as g u i c k l y as under the " o p p o r t u n i t y l i f e " approach. In the e a r l y years the lower d e p r e c i a t i o n charges dominate. L a t e r , however, the higher c o s t of c a p i t a l overwhelms t h i s component and l e a d s to higher t o t a l c o s t s over the p r o j e c t ' s o p e r a t i n g l i f e . Thus the ranking of S i t e C and Hat Creek i s a l s o dependent on the type of d e p r e c i a t i o n p o l i c y employed. The s i m i l a r i t y i n u n i t cost f o r the thermal p r o j e c t s under the two d e p r e c i a t i o n procedures r e s u l t s from the f a c t t h a t these p r o j e c t s have an expected l i f e c l o s e t o t h a t of the economy-wide average l i f e . The use of the economy-wide annual d e p r e c i a t i o n r a t e o f 5 . 7 percent a p p l i e d to a d e c l i n i n g balance measure of c a p i t a l stock g i v e s remarkably s i m i l a r u n i t c o s t s to those generated by the "op p o r t u n i t y l i f e " s t r a i g h t l i n e d e p r e c i a t i o n method. The high e r t o t a l c o s t s a s s o c i a t e d w i t h t h i s method i n the e a r l y years are almost e x a c t l y balanced by lower c o s t s i n l a t e r y e ars. T h i s s i m i l a r i t y w i l l prove h e l p f u l , s i n c e we w i l l l a t e r use t h i s method i n su b r o u t i n e COSTS because of the d i f f i c u l t i e s i n h e r e n t i n keeping t r a c k of t e r m i n a t i n g dates f o r a v a r i e t y of d i f f e r e n t p r o j e c t s . Although not shown on Table 1 , a s e n s i t i v i t y a n a l y s i s of the impact of d i f f e r e n t assumptions about f u e l c o s t s was a l s o 75 performed. I f the c o s t o f c o a l i s taken to be the a n t i c i p a t e d e x t r a c t i o n c o s t s plus today's r o y a l t y r a t e s ( r a t h e r than the o p p o r t u n i t y c o s t used i n the base c a s e ) , u n i t c o s t s f o r the three c o a l p r o j e c t s shown f a l l by 2 m i l l s per KWH. T h i s makes these thermal p l a n t s a c l e a r f a v o u r i t e over the S i t e C hydro f a c i l i t y . 5.1.3 P r o j e c t Banking A f i r s t g l ance at the energy p r o j e c t s l i s t e d i n Table 1 might suggest a s u b s t a n t i a l v a r i a t i o n between the r a n k i n g suggested by the base case r e s u l t s and t h a t adopted by B.C. Hydro. However, with the e x c e p t i o n of the East Kootenay thermal p l a n t , t h i s apparent d i f f e r e n c e i s i l l u s o r y . The two d i v e r s i o n schemes, with t h e i r u n u s u a l l y low c o s t s , are scheduled by B.C. Hydro to begin o p e r a t i o n a t the e a r l i e s t p o s s i b l e i n - s e r v i c e date. Hat Creek I I must await the development of Hat Creek I b e f o r e i t can proceed. In the case of t h e East Kootenay c o a l p l a n t , t h i s p r o j e c t has two important d e t r a c t i o n s not r e f l e c t e d i n the economic a n a l y s i s . The f i r s t concerns i t s d i s t a n c e from the major lo a d c e n t r e s , with important i m p l i c a t i o n s f o r the s t a b i l i t y and r e l i a b i l i t y of the t r a n s m i s s i o n system. The second c e n t r e s around access to the c o a l . B.C. Hydro does not now h o l d mining r i g h t s to c o a l i n the area and, as a r e s u l t has not proceeded very f a r i n i t s a n a l y s i s of t h i s o p t i o n . For these reasons, the p r o j e c t o r d e r i n g that i s adopted i n s u b r o u t i n e APPROVE i s the same as t h a t recommended by B.C. Hydro i n i t s 1975 Task Force Beport. S i t e C i s assumed to come on 76 stream a f t e r East Kootenay c o a l i f a d d i t i o n a l g e n e r a t i n g c a p a c i t y i s r e g u i r e d . 5 * Energy from the s m a l l and i n e x p e n s i v e Kootenay River D i v e r s i o n i s programmed to be a v a i l a b l e i n 1984 r e g a r d l e s s of the supply-demand balance of the time. The McGregor D i v e r s i o n and the "middle U n i t s " of the Revelstoke and S i t e C hydro p r o j e c t s are s l a t e d t o be o p e r a t i o n a l as soon as p o s s i b l e , s u b j e c t to t h e r e being a f o r e c a s t need f o r new generating f a c i l i t i e s . . The base case u n i t c o s t s f o r the c a p a c i t y p r o j e c t s a l s o c a l l f o r some e x p l a n a t i o n . The gas t u r b i n e s on Vancouver I s l a n d are r e g u i r e d because of a n t i c i p a t e d l i m i t a t i o n s on the c a p a c i t y of the t r a n s m i s s i o n l i n e s c a r r y i n g power to t h i s e l e c t r i c i t y - d e f i c i e n t area. The high u n i t c o s t f i g u r e shown i n Table 1 r e s u l t s from the assumed c a p a c i t y f a c t o r of 50 p e r c e n t . 5 5 a lower c a p a c i t y f a c t o r would reduce t h i s f i g u r e s u b s t a n t i a l l y , although i t would never f a l l below that of any of the hydro peaking p r o j e c t s . The tenth U n i t at the Shrum p l a n t on the Peace R i v e r , while not producing a d d i t i o n a l energy, can be used to d i s p l a c e more c o s t l y U n i t s now performing t h i s r o l e , thereby p r o v i d i n g a saving which does not appear i n our a n a l y s i s . Thus f o r peaking p r o j e c t s , we can again rank the v a r i o u s options i n a manner c o n s i s t e n t with t h a t adopted by B.C. Hydro 5 * T h i s i s c o n s i s t e n t with the base case r a n k i n g i n our a n a l y s i s . However, as has been noted, the o p t i m a l p o s i t i o n i n g of S i t e C r e l a t i v e t o the thermal p r o j e c t s i s s e n s i t i v e to a l t e r a t i o n s i n s e v e r a l key assumptions. There i s some i n d i c a t i o n |based on p r i v a t e d i s c u s s i o n s and statements i n the media) t h a t S i t e C i s now becoming r e l a t i v e l y more a t t r a c t i v e i n the eyes of B.C. Hydro. I t d i d not f i g u r e i n the 1975-1990 Plan proposed by the 1975 Task Force Report. 5 5 C a p a c i t y f a c t o r i s the r a t i o of the average load on a machine f o r the p e r i o d of time c o n s i d e r e d , to the c a p a c i t y r a t i n g of the machine. 77 i n 1975. The Vancouver I s l a n d gas t u r b i n e s are brought on when the demand f a c i n g the t o t a l system reaches a s p e c i f i e d l e v e l . 5 6 The remaining p r o j e c t s are t r i g g e r e d as r e q u i r e d t o meet a f o r e c a s t c a p a c i t y d e f i c i t , i n the order i n which they are l i s t e d i n Table 1. 5.2 C o n v e n t i o n a l Accounting P r o j e c t i o n s 5.2.1 Base Case T h i s s e c t i o n f o r e c a s t s key f i n a n c i a l v a r i a b l e s based upon accounting conventions c o n s i s t e n t with those now employed by B.C. Hydro. The e l e c t r i c a l demand growth r a t e i s t h a t s p e c i f i e d i n the 1975 Task Force Report, as are the b a s i c c o s t data and the f o l l o w i n g exogenous assumptions. The i n f l a t i o n r a t e i s 15 percent i n 1975, 10 percent between 1976-1979 and 5 percent t h e r e a f t e r . The nominal e f f e c t i v e i n t e r e s t r a t e on new bonds i s 10 percent throughout the 1975-1990 p e r i o d . 5 7 Other key assumptions are t h a t the p r o j e c t s are i n i t i a t e d a c c o r d i n g t o subroutine APPROVE, t h a t water c o n d i t i o n s are average and that f u e l i s p r i c e d at i t s o p p o r t u n i t y value. In the next s e c t i o n we w i l l r e l a x each of these assumptions and examine 5 6 We assume t h a t the r e g i o n a l balance of e l e c t r i c a l demand w i l l h o l d the p a t t e r n suggested by B.C. Hydro i n the Task Force Report. T h i s i m p l i e s that the demand on the I s l a n d w i l l be a t the l e v e l r e q u i r i n g gas t u r b i n e s when the p r o v i n c i a l demand i s at the l e v e l which t r i g g e r e d the t u r b i n e s i n the 1975 Report. 5 7 The f a i l u r e by B.C. Hydro t o l i n k i n f l a t i o n and nominal i n t e r e s t r a t e s could prove to be a problem. However, over the 1975-1990 p e r i o d , the r a t e of i n f l a t i o n averages an annual compound r a t e of 6.4 percent which i s not i n c o n s i s t e n t with a 10 percent nominal r a t e on low r i s k bonds. 78 the r e s u l t i n g impact., Table 2 summarizes some of the p r o j e c t i o n s under these assumptions. 'Energy Generated 1 c o n s i s t s of gross demand i n B.C. Hydro's s e r v i c e area p l u s any exports t h a t are both e c o n o m i c a l l y a t t r a c t i v e to the A u t h o r i t y and demanded by those o u t s i d e the province (under the 50 percent o f export p o t e n t i a l assumption). 'Investment' i s c a l c u l a t e d by summing the r e a l c a p i t a l e x p e n d i t u r e s r e g u i r e d to meed demand growth and c o n v e r t i n g these i n t o nominal d o l l a r s through the p r i c e l e v e l i n d e x . s s 'Gross Debt* i s the sum of bonds i s s u e d p r i o r to 1976 t h a t w i l l s t i l l be outstanding each year p l u s the new debt r e g u i r e d to meet c a p i t a l and f i n a n c i a l reguirements i n excess of what can be generated i n t e r n a l l y under the new net income p o l i c y . 'Annual Costs* comprise f i x e d and o p e r a t i n g c o s t s , a l l l o c a l and water taxes, d e p r e c i a t i o n and net i n t e r e s t charges and any net income. They are a l s o expressed i n nominal terms. The f i n a l column, •Cost per KWH* i s simply t o t a l annual c o s t s (now converted t o 1976$) d i v i d e d by the energy generated. 5.2.2 S e n s i t i v i t y A n a l y s i s In order t o a p p r e c i a t e the importance of s e v e r a l key assumptions, we examine the impact on the average r e a l c o s t per KWH over t h i s p e r i o d when these assumptions are a l t e r e d . The r e s u l t s are reported i n Table 3. We f i r s t disengage s u b r o u t i n e APPROVE and e x p l i c i t l y r e a d 5 9 I t i s i n t e r e s t i n g to note t h a t the 1976-19 81 investment shown here t o t a l s w i t h i n H percent of t h a t p r o j e c t e d i n a November 1976 Prospectus by the A u t h o r i t y (1976b,18). In f a c t , t h e i r f i g u r e s are higher than those shown i n t h i s T a b le. TABLE 2 1976-1990 PROJECTION OF KEY FINANCIAL VARIABLES ENERGY YEAR GENERATED INVESTMENT (MM KWH/YR) (MM NOMINAL $/YR) 1976 25,102 526 1977 28,402 542 1978 31,544 702 1979 35,321 983 1980 39,097 1181 1981 43,095 1019 1982 47,427 1123 1983 52,092 1133 1984 56,868 1125 1985 61,866 1344 1986 67,198 1428 1987 72,973 1603 1988 78,860 1729 1989 84,858 1790 1990 91,189 1400 GROSS ANNUAL COST PER DEBT COSTS KWH HISTORIC $) (MM NOMINAL $) (1976 $) (MILLS/KWH) 3932 463 , 18 4340 535 17 4960 624 16 5883 800 17 6981 990 17 7834 1120 17 8721 1413 18 9629 • 1600 18 10,458 1925 19 11,463 • 2191 19 12,488 2457 19 13,674 2879 19 14,885 3226 19 16,208 3775 20 17,053 4144 19 80 i n the a p p r o p r i a t e approval dates f o r major p r o j e c t s as given i n the 1975 Task Force Report. Average cost per KWH d u r i n g the 1976-1990 p e r i o d f a l l s from 18.1 to 17.9 m i l l s . There are two reasons f o r t h i s r e d u c t i o n . The f i r s t i s t h a t the appr o v a l dates i n the Task Force f o r new peaking p r o j e c t s are t o o l a t e to prevent the l o s s o f l o a d p r o b a b i l i t y from r i s i n g above i t s de s i r e d maximum i n three d i f f e r e n t years. Subroutine APPROVE, on the other hand, f o l l o w s the s t a t e d r e l i a b i l i t y c r i t e r i o n and approves f o u r of these peaking p r o j e c t s a year e a r l i e r than does the Task Force. The second reason concerns the f i n e t u n i n g done i n the Task Force which enables optimal economic timing o f new p r o j e c t s . Because of the r e l a t i v e l y high c o s t of running Burrard, s e v e r a l c o a l - f i r e d D n i t s are brought on e a r l i e r i n the Task Force than are r e q u i r e d from a t e c h n i c a l p e r s p e c t i v e , thereby d i s p l a c i n g g a s - f i r e d energy., Subroutine APPROVE a l s o i n i t i a t e s S i t e C f o r commencement i n 1990 while the Task Force shows a very s l i m energy margin i n 1990 {the t e r m i n a l year) and thus never b u i l d s t h i s p r o j e c t . 81 TABLE 3 SENSITIVITY ANALYSIS ON THE AVERAGE COST/KWH IN THE 1976-1990 PERIOD J976 $ MILLS/KWH BASE CASE 18. 1 TASK FORCE APPROVAL DATES 17.9 CRITICAL WATER CONDITIONS 20.4 ACTUAL FUEL PRICES 17.3 Despite these d i f f e r e n c e s , the Task Force plan e f f e c t s a sa v i n g of only one percent i n average u n i t c o s t s over t h i s p e r i o d . Two-thirds o f the gen e r a t i o n p r o j e c t s (16) are approved at the same time under both runs. Seven others d i f f e r only by one year, while one p r o j e c t has a two year d i f f e r e n c e . Another v a r i a t i o n on the base case r e s u l t s from changing the assumption about water c o n d i t i o n s . Table 3 shows t h a t under c r i t i c a l c o n d i t i o n s (the d r i e s t f i v e y e ars i n recorded h i s t o r y ) , average c o s t r i s e s from 18.1 to 20.4 m i l l s per KWH. P r o j e c t approval dates do not change s i n c e planning i s done on the b a s i s 82 of c r i t i c a l conditions. However, l e s s water means more use of expensive thermal f a c i l i t i e s . Under these conditions, the Burrard plant operates at capacity i n most years and the expensive gas turbines are also reguired to produce energy. Hence the 13 percent increase i n average cost during t h i s period. The f i n a l assumption to be altered i s that of f u e l prices. If natural gas and coal are priced at their estimated 1976 cost {rather than t h e i r opportunity value), average costs f a l l from 18.1 to 17.3 m i l l s per KWH. This drop would be more noticeable during c r i t i c a l water conditions when the thermal plants are r e l i e d upon more heavily. 5.2.3 Interpretation Having established the basic s t a b i l i t y of the average cost per KWH over the 1976-1990 period to several important variations i n the underlying assumptions, we turn now to examine in more d e t a i l the r e l a t i v e changes in the component costs. Table 4 summarizes the increases in the base case quantity and costs between 1976 and 1990. Column 4 presents the changes i n various categories of r e a l costs during t h i s period, while the f i n a l column shows these changes r e l a t i v e to the change i n the number of kilowatt-hours. looking f i r s t at the annual operating costs, we see a sharp increase i n variable costs (mainly fuel) which i s consistent with the swing toward thermal generation f a c i l i t i e s . School taxes show a r e l a t i v e l y moderate increase r e f l e c t i n g an assumption about a greater share of the authority's f a c i l i t i e s TABLE 4 RELATIVE COST CHANGES: 1976-1990 (1) 1976 (MWT CAPITAL CHARGES NET INTEREST DEPRECIATION . NET INCOME OPERATING CHARGES VARIABLE FIXED SCHOOL TAXES GRANTS & LAND TAXES WATER FEES TOTAL COSTS PRODUCTION (MM KWH) 214 72 0 18.7 123 21.2 4.4 9 463 25,102 (2) 1990 (NOMINAL MM$) 1262 506 379 835 823 253 39.4 48 4145 91,109 (3) 1990 (1976 MM $) 530 213 159 351 346 106 16.5 20 1741 (4) 1990 COSTS (76$) 1976 COSTS"! 76$) ( 3 ) / ( l ) 2.5 3.0 18.8 2.8 5.0 3.7 2.2 3.8 3.6 (5) COST CHANGE RELATIVE TO QUANTITY CHANGE (4)/3.6 .69 .83 5.2 .78 1.4 1.0 .61 1.1 1.0 84 being s u b j e c t to t h i s l e v y i n the f u t u r e . , M u n i c i p a l ' g r a n t s 1 and. land taxes i n c r e a s e i n r e a l terms a t the same r a t e as produc t i o n . Water l i c e n c e f e e s , as would be expected, show a r e d u c t i o n i n t h e i r r e l a t i v e share o f c o s t s . The moderate r e d u c t i o n ( i n r e l a t i v e terms) of f i x e d o p e r a t i n g c o s t s deserves some comment. These c o s t s c o n s i s t of f i x e d o p e r a t i n g , maintenance, a d m i n i s t r a t i o n and gen e r a l expenses plus insurance and i n t e r i m replacement expenditures. They are determined by adding to the 1975 l e v e l of f i x e d o p e r a t i n g c o s t s those new c o s t s a s s o c i a t e d with a d d i t i o n a l f a c i l i t i e s . T h i s l a t t e r f i g u r e i s determined by a p p l y i n g a c o e f f i c i e n t to the r e a l c a p i t a l c o s t of the v a r i o u s types o f new f a c i l i t i e s . T h i s c o e f f i c i e n t i n c r e a s e s over time to r e f l e c t r e a l labour c o s t changes. , The move towards l e s s c a p i t a l - i n t e n s i v e generation p l a n t s i s more than o f f s e t by the much g r e a t e r f i x e d o p e r a t i n g c o s t s a s s o c i a t e d with these f a c i l i t i e s . These two f a c t o r s would tend t o i n c r e a s e the r e l a t i v e share of these c o s t s , assuming the b a s i c mix of the system between the v a r i o u s types of non-generating f a c i l i t i e s remained approximately constant. The r e l a t i v e r e d u c t i o n that r e s u l t s from using the f i g u r e s contained in the Task Force Report (and subseguent i n t e r v i e w s ) suggests the e v o l u t i o n of technology towards t h a t r e q u i r i n g r e l a t i v e l y fewer of these f a c t o r s (in an economic se n s e ) . A l t e r n a t i v e l y , i t c o u l d s i g n a l the e x i s t e n c e of c u r r e n t l y unexploited economies of s c a l e which w i l l be r e a l i z e d with the 85 anticipated expansion. 5 9 On balance, annual operating costs show an increase i n r e a l terms compared to the change i n output. Capital charges, on the other hand, exhibit the opposite trend. The depreciation charge consists of the amount that was levied on f a c i l i t i e s i n 1975 plus the inverse of the expected l i f e of new f a c i l i t i e s applied to the h i s t o r i c d o l l a r cost of these f a c i l i t i e s . Depreciation on the eguipment i n service in 1975 remains constant i n nominal terms, leading to a sharp decline i n r e a l terms over the period under examination. S i m i l a r l y , the annual charge on f a c i l i t i e s being placed i n service prior to 1990 w i l l also decline i n r e a l terms. Contributing to t h i s trend i s the fact that the new thermal generating plant requires less i n i t i a l c a p i t a l per KWH generated, a f a c t which s l i g h t l y more than o f f s e t s i t s reduced service l i f e and hence higher rate of depreciation. Net i n t e r e s t charges, the largest component of annual t o t a l costs, drop f a i r l y s u b s t a n t i a l l y r e l a t i v e to the increase in output during t h i s period. These charges consist of interest on the debt issued prior to 1976 that w i l l s t i l l be outstanding each year plus gross interest on post-75 debt less i n t e r e s t during construction. Some two-thirds of the pre-1976 debt w i l l remain outstanding in 1990, and the interest payments thereon, while remaining constant i n nominal terms, w i l l f a l l rapidly i n r e a l d o l l a r s during t h i s period. Interest charges on the debt issued subsequent to 1975 5 9 On the other hand, i t could indicate an underestimation of these c o e f f i c i e n t s or an overestimation by the author of the fixed costs ( r e l a t i v e to the variable costs) i n the i n i t i a l year of the simulation. 86 depends on the q u a n t i t y of such debt and the a s s o c i a t e d i n t e r e s t r a t e . In the p e r i o d 1976-1990, gross o u t s t a n d i n g debt i n c r e a s e s only 1.8 times i n r e a l terms (see Table 2). T h i s r e l a t i v e l y moderate i n c r e a s e r e s u l t s from s e v e r a l f a c t o r s . New g e n e r a t i n g p r o j e c t s are l e s s c a p i t a l - i n t e n s i v e and u n e x p l o i t e d economies of s c a l e i n downstream f a c i l i t i e s c o u l d r e s u l t i n p r o p o r t i o n a l l y l e s s c a p i t a l spending i n the f u t u r e . More funds are generated i n t e r n a l l y through net income or p r o f i t s . And the measurement of outstanding debt i n h i s t o r i c d o l l a r s l e a d s to i t s c o n t i n u a l d e c l i n e i n r e a l terms during a p e r i o d of i n f l a t i o n . T h i s l a s t c o n s i d e r a t i o n i s somewhat o f f s e t by the f a c t t h a t i n t e r e s t r a t e s i n c o r p o r a t e an e x p e c t a t i o n about i n f l a t i o n . The i n f l a t i o n premium contained i n nominal i n t e r e s t r a t e s i s r e f l e c t e d i n an i n c r e a s e of net i n t e r e s t payments r e l a t i v e to gross outstanding debt of from 5.4 percent i n 1976 t o 7.4 percent i n 1990. The net e f f e c t o f these c o n f l i c t i n g f o r c e s i s a r e l a t i v e r e d u c t i o n i n r e a l net i n t e r e s t charges over t h i s p e r i o d . As i n d i c a t e d i n Table 2, our model using c o n v e n t i o n a l accounting technigues i n d i c a t e s an e s s e n t i a l l y s t a b l e p a t t e r n i n r e a l c o s t s per KWH between 1976 and 1990. 6 0 T h i s r e s u l t i s c o n s i s t e n t with B.C. Hydro's own f o r e c a s t i n g and i s the j u s t i f i c a t i o n f o r t h e i r long term g o a l of f l a t t e n i n g the r a t e s t r u c t u r e . T h i s s e c t i o n o f the paper has i n d i c a t e d the d i s t o r t i o n s i n h e r e n t i n t h i s accounting framework d u r i n g p e r i o d s 6 0 T h i s r e s u l t i s c l e a r l y dependent upon assumptions about the r a t e of i n f l a t i o n . I f t h e f i g u r e s used i n t h i s paper t u r n out to overestimate f u t u r e g e n e r a l p r i c e l e v e l i n c r e a s e s , then r e a l c o s t s w i l l r i s e more q u i c k l y than i n d i c a t e d . 87 of i n f l a t i o n . In e a r l i e r chapter pointed out other fundamental weaknesses i n using t h i s methodology as a s o l e b a s i s f o r e s t a b l i s h i n g a r a t e s t r u c t u r e . We tu r n now to look at the r e s u l t s of the approach designed to determine the marginal economic c o s t s of the B.C. Hydro system. 5.3 Determination Of Marginal Cost 5.3.1 Base Case In t h i s s e c t i o n we present the r e s u l t s of an economic a n a l y s i s o f the impact on c o s t s of v a r i o u s demand shocks. In order to i s o l a t e the cost e f f e c t of changes i n peak as d i s t i n c t from energy demand, two runs are performed f o r a given energy shock. One run assumes t h a t the shock has an impact on the system's off-peak p e r i o d s only and does not a l t e r B.C. Hydro's annual peak demand. The other assumes t h a t the change has a l o a d f a c t o r i d e n t i c a l to t h a t o f the system's average, thus a f f e c t i n g both peak and off-peak demand. The c o s t d i f f e r e n t i a l between the two runs i s a t t r i b u t a b l e s o l e l y t o the change i n peak demand. The model a l s o d i s t i n g u i s h e s between the c o s t changes f o r the l a r g e customers t a k i n g power at the s u b - t r a n s m i s s i o n l e v e l and the s m a l l e s t customers who a l s o r e g u i r e the f u l l d i s t r i b u t i o n system. Because of the d i s c o n t i n u i t i e s l i k e l y as a r e s u l t of the mechanical p r o j e c t approval process used i n t h i s model, a v a r i e t y of long-term demand shocks are t e s t e d . They range from 10 m i l l i o n KWH a year (.04 percent of present energy demand) to 88 5 b i l l i o n KWH annua l l y {19.9 percent) f o r both an i n c r e a s e and decrease i n demand. In the s h o r t run, these demand shocks a r e accommodated by v a r y i n g the amount t h a t each f a c i l i t y i s used. In the l o n g e r term, the investment programme i s a d j u s t e d to best f i t the new demand p r o j e c t i o n s . 6 1 The standard assumptions o u t l i n e d i n the p r e v i o u s base case s i m u l a t i o n s c o n t i n u e i n e f f e c t . T h i s i n c l u d e s the assumption that one-half of the export market t h a t i s ec o n o m i c a l l y a t t r a c t i v e f o r B.C. Hydro t o serve i s a c t u a l l y a v a i l a b l e . We a l s o assume that the demand shock i n t r o d u c e d i n 1976 conti n u e s at the same f i x e d l e v e l f o r the d u r a t i o n of the s i m u l a t i o n p e r i o d . The demand shock does not c o n s i s t of any changes i n the number of e l e c t r i c a l customers served by B.C. Hydro. T h i s i s assumed t o grow at the r a t e i n d i c a t e d i n the 1975 Task Force Report. In the next s e c t i o n , we review the impact of a l t e r i n g these assumptions. Table 5 presents the r e s u l t s of the i n t r o d u c t i o n of v a r i o u s demand shocks. The f i r s t column i n d i c a t e s the s i z e , d i r e c t i o n and system load f a c t o r of the p e r t u r b a t i o n . The next two show the discounted present value of the energy and peak ge n e r a t i o n over the 55 year s i m u l a t i o n p e r i o d r e l a t i v e to t h a t without the demand shock. Columns 4 and 5 present the i n c r e a s e or decrease i n the discounted present value ( i n 1976 d o l l a r s ) t o the l a r g e s t and s m a l l e s t customers over t h i s p e r i o d r e s u l t i n g from the changes i n demand. The f i n a l f o u r columns convert t h i s i n f o r m a t i o n i n t o 1976 6 1 I f demand r i s e s above the Task Force's f o r e c a s t 1990 l e v e l , S i t e C i s used t o meet energy d e f i c i t s while new gas t u r b i n e s supply any peaking shortage. GO TABLE 5 MARGINAL ECONOMIC COSTS FOR VARIOUS DEMAND SHOCKS DEMAND SHOCK SYSTEM LOAD P.V. ENERGY P.V. PEAK P.V. LARGE P.V. SMALL (MM. i r a ) FACTOR OF SHOCK GENERATED (Mil KWH) GENERATED (M W) CUSTOMER COSTS (MM 76$) CUSTOMI COSTS (MM 76? BASE CASE 1,393,223.0 249335. . 1 16699. 2 20738.7 -10 63.5% -198.0 -39.4 -4.2 -4.7 -10 off - p e a k -198.0 0.0 -3.9 -4.1 -100 63. 5% -5255.0 -397.5 -585.4 -589.8 - 100 off - p e a k -5129.0 0.0 -565.1 -567.4 -1000 63.5% -27,114.0 -39S6.8 -727.5 I -771.8 -1000 off - p e a k -27,114.0 0.0 -577.6 -599.2 -3000 63.5% -67,750.0 -11,963. ,1 -1851. 3 -1984.1 -3000 off - p e a k -67,750.0 0.0 -1530. 2 -1595.1 -5000 63. 5% -107,422.0 -19,941. .8 -2441/5 -2662.9 -5000 off - p e a k -107,422.0 0.0 -2060. 5 -2168.7 +10 63.5% 195.0 42. .2 4. 2 4.7 +10 off - p e a k 195.0 0. .0 3. 9 4.1 +100 63.5% 1979.0 400. ,5 42. 3 • 46.7 + 100 off - p e a k 1979.0 0. ,0 38. 7 40.8 +1000 63,5% 16,994.0 3989. .5 -165. 7 -121.5 +1000 off - p e a k 16,994.0 0. .0 -236. 2 -214.6 +3000 63.5% 60,795.0 11,965. 5 1206. 9 1339.6 +3000 off - p e a k 60,671.0 0. ,0 1046. 1 1111.0 +5000 - 63.5% 101,668.0 19,945. .6 2060. 8 2282.1 +5000 off - p e a k 101,668.0 0. .0 1572. 0 1680.1 AVERAGE: AVERAGE MARGINAL ENERGY AND CAPACITY COST FOR ENTIRE SYSTEM: LARGE CUSTOMERS SMALL CUSTOMEP.S ENERGY COST CAPACITY COST ENERGY COST CAPACITY COST 76$ MILLS/KWH) (76$ MILLS/KWH) (76$ MILLS/KWH) (76S MILLS/K'iVK) 19.7 1.5 20.7 3.0 110.2 1.2 110.6 1.6 21.3 5.5 22.1 6.4 22.6 4.7 23.5 5.S 19.2 3.5 20.2 4.6 20.0 1.5 21.0 3.1 19.6 1.8 20.6 3.0 13.9 4.1 L2.6 5.5 17.2 2.5 18.3 3.8 15.5 4.8 16.5 6.9 19.4 3.2 20.3 4.6 90 m i l l s per KWH. Column 6 i s obtained by d i v i d i n g the r e s u l t s of column 4 by those i n column 2 f o r the off-peak shock. Column 7 i s d e r i v e d by t a k i n g the i n c r e m e n t a l c o s t i n column 4 r e s u l t i n g from the on-peak shock and d i v i d i n g i t by the g u a n t i t y i n column 2. The r e s u l t i s the c o s t a t t r i b u t a b l e to the change i n peak demand expressed i n m i l l s per KWH under an assumed l o a d f a c t o r of 63.5 percent. The l a s t two columns perform a s i m i l a r c a l c u l a t i o n f o r the s m a l l customer using the c o s t f i g u r e s shown i n column 5. The r e s u l t s shown i n Table 5 merit some comment. G e n e r a l l y , the change i n the g u a n t i t y o f energy generated i s independent of the load f a c t o r of the demand shock. For two of the demand changes, however, there are s m a l l d i f f e r e n c e s caused by a l t e r i n g the load f a c t o r assumption. A c l o s e r examination of the workings of the model r e v e a l that the d i f f e r e n t peak demands t r i g g e r p r o j e c t s designed p r i m a r i l y to supply c a p a c i t y but which a l s o have an energy component. T h i s new energy c a p a b i l i t y i s then e i t h e r exported or i s i n c l u d e d i n the energy c a l c u l a t i o n s , thereby d e l a y i n g the s t a r t o f new energy p r o j e c t s . The r e s u l t s generated i n the l a s t four columns show c o n s i d e r a b l e c o n s i s t e n c y with two notable e x c e p t i o n s . Upon c l o s e r examination, these anomalies appear t o r e s u l t from the lack of f i n e t u n i n g i n h e r e n t i n t h i s model and the d i s t o r t i o n s caused by using a cut o f f date f o r demand growth. The b a s i c problem concerns the r o l e of S i t e C which, under the base case, i s t r i g g e r e d f o r commencement i n 1990 to meet a s m a l l f o r e c a s t energy d e f i c i e n c y . As 1990 r e p r e s e n t s the l a s t year of demand growth, t h i s new p r o j e c t operates f a r below i t s energy 91 c a p a b i l i t y , a s i t u a t i o n only p a r t l y m i t i g a t e d under the assumed export market c o n d i t i o n s . Thus, i n the case of the demand shock of -100 m i l l i o n KWH, t h i s p r o j e c t i s no longer r e g u i r e d and l a r g e c o s t s a v i n g s are experienced r e l a t i v e to the r e d u c t i o n i n the g u a n t i t y of energy generated. Hence the a r t i f i c a l l y l a r g e savings i n m i l l s per KWH shown to r e s u l t from t h i s r e d u c t i o n . In the case of the 1000 m i l l i o n KWH shock, thermal p r o j e c t s are a c c e l e r a t e d with the r e s u l t t h a t i n 1990 S i t e C i s not r e g u i r e d and i s never t r i g g e r e d . T h i s i s r e f l e c t e d i n the c o s t r e d u c t i o n r e s u l t i n g from the demand i n c r e a s e . The f i g u r e s at the bottom of the t a b l e f o r the l a s t f o u r columns rep r e s e n t the mean o f the o b s e r v a t i o n s i n the column. The r e s u l t s of the two anomalous runs j u s t d i s c u s s e d are not i n c l u d e d i n t h i s averaging. The use of a v a r i e t y of s i z e s and d i r e c t i o n s of demand shocks should minimize d i s t o r t i o n s caused by the a r b i t r a r y d e c i s i o n r u l e s followed i n the model. The average f i g u r e s shown i n columns 7 and 9 f o r the c a p a c i t y c o s t , assuming a 63.5 percent l o a d f a c t o r , are approximately equal to $18.00 and $26.00 per k i l o w a t t , r e s p e c t i v e l y . 5.3.2 S e n s i t i v i t y A n a l y s i s In order to understand the s e n s i t i v i t y o f these r e s u l t s t o v a r i a t i o n s i n some of the u n d e r l y i n g assumptions, s e v e r a l a l t e r n a t i v e s i m u l a t i o n s were performed. These a l t e r n a t i v e s i n t r o d u c e d demand shocks o f 10, 1000 and 5000 m i l l i o n KWH i n both d i r e c t i o n s under an assumed lo a d f a c t o r c o i n c i d i n g with the 63.5 percent p r o j e c t e d f o r the system. As such, the r e s u l t s can be compared with the combined energy and c a p a c i t y average 92 marginal c o s t of 22.6 m i l l s per KWH f o r l a r g e customers. , We f i r s t a l t e r the f r a c t i o n o f the ec o n o m i c a l l y a t t r a c t i v e export market a v a i l a b l e t o B.C. Hydro from 50 to 100 percent. T h i s enables a smoother r e a c t i o n to the demand shocks by a l l o w i n g the export market to absorb more of the d i f f e r e n c e . The r e s u l t i n g average marginal c o s t f o r the l a r g e customers becomes 23.6 m i l l s per KWH under t h i s assumption. We next a l t e r the t i m i n g o f the demand shock. By d e l a y i n g the i n t r o d u c t i o n of the permanent change from 1976 to 1980, the average marginal c o s t r i s e s s l i g h t l y from 22.6 to 22.9 m i l l s per KWH. The i n t r o d u c t i o n of the shock f o r only the year 1976 y i e l d s a short-term average marginal c o s t of 20.7 m i l l s . The amount o f energy p r o j e c t e d f o r g e n e r a t i o n i n the Burrard p l a n t t h a t year was approximately 1000 m i l l i o n KWH, as compared with i t s annual energy c a p a b i l i t y o f 5520 m i l l i o n KWH. The l a r g e 1976 shock of 5000 m i l l i o n KWH r e s u l t e d i n an average marginal c o s t o f 23.8 m i l l s per KWH, r e f l e c t i n g the need t o begin g e n e r a t i n g energy from the c o s t l y gas t u r b i n e s . Conversely, the 1976 shock of 5000 m i l l i o n KWH l e d onl y t o an average marginal c o s t of 16.5 m i l l s per KWH because of the minimal s a v i n g s p o s s i b l e through r e d u c t i o n i n the amount of h y d r o - e l e c t r i c generated energy. F i n a l l y , we examine the impact on c o s t s of a l t e r i n g the number o f s m a l l new customers assumed t o be served by B.C. Hydro. The r e s u l t s i n Table 5 show the u n i t c o s t of changes i n f o r e c a s t e d energy and/or peak demand f o r two customer c l a s s e s assuming no change i n the f o r e c a s t number of customers connected to the system. We now i n t r o d u c e a shock which, beginning i n 1976, permanently a l t e r s by a f i x e d increment the number o f 93 small connected customers without a f f e c t i n g the e l e c t r i c a l demand forecasts. The i n i t i a l connection charges plus subseguent annual service costs indicate an approximate average annual cost associated with connecting a new small customer of $60.00. 6 2 5.3.3 Interpretation We turn now to an interpretation of the r e s u l t s i n Table 5 and a comparison of them with the figures generated e a r l i e r i n this chapter. From the outset, i t i s important to recognize that the numbers shown are not to be taken as accurate to the f i n a l decimal point, but rather represent an approximation of the relevant marginal economic costs. Perhaps the most i n t e r e s t i n g r e s u l t revealed i n Table 5 i s the heavy predominance of the energy over the peak demand component of marginal costs. For the large customers, over 85 percent of the incremental costs associated with a long-term e l e c t r i c a l demand change (corresponding to the system's load factor of 63.5 percent) are associated with the change i n the energy component of the load. This i s consistent with the f a c t that for the e n e r g y - c r i t i c a l B.C. Hydro system, a change i n the energy demand i s f i r s t met by a l t e r i n g the guantity of fuel used at the Burrard plant and then by varying the st a r t i n g dates of major generation and transmission projects. Changes i n peak demand, on the other hand, do not immediately af f e c t the generation planning programme due to the existence of excess reserve capacity, although a permanent 6 2 This figure should be viewed with considerable caution as there i s an inadeguate amount of p u b l i c l y available data to estimate these costs with much confidence. 9a a l t e r a t i o n w i l l e v e n t u a l l y i n f l u e n c e the timing of new c a p a c i t y - only p r o j e c t s . These, however, are r e l a t i v e l y i n e x p e n s i v e , r e g u i r e no new a s s o c i a t e d t r a n s m i s s i o n f a c i l i t i e s , and must be discounted when viewed from 1976. Immediate responses w i l l be f e l t i n the investment on the major t r a n s m i s s i o n , sub- tra n s m i s s i o n and tr a n s f o r m a t i o n f a c i l i t i e s , but these are small compared with the major generation and a s s o c i a t e d t r a n s m i s s i o n l i n e e x p e n s e s . 6 3 Another i n t e r e s t i n g r e s u l t of t h i s a n a l y s i s i s the proximity of the inc r e m e n t a l c o s t s a s s o c i a t e d with demand shocks emanating from the l a r g e s t and s m a l l e s t customers. In the case of a change i n energy demand, the s i m i l a r i t y r e s u l t s from the f a c t t h a t e i t h e r source o f change w i l l r e g u i r e the same adjustment i n the ge n e r a t i o n and a s s o c i a t e d t r a n s m i s s i o n l i n e programme. The o n l y reason f o r the s l i g h t d i f f e r e n c e i n t h i s category between the two customer c l a s s e s i s the assumption t h a t investment i n "miscellaneous e l e c t r i c p l a n t " i s energy r e s p o n s i v e and i s twice that f o r s m a l l customers as f o r l a r g e . The r e l a t i v e l y greater c o s t s a s s o c i a t e d with changes i n the c o i n c i d e n t peak demand of the s m a l l e r customers r e f l e c t s the a d d i t i o n a l adjustment i n downstream t r a n s f o r m a t i o n and d i s t r i b u t i o n f a c i l i t i e s t h a t would be e n t a i l e d . The r e s u l t s o f the marginal cost a n a l y s i s would a l s o appear to be q u i t e c o n s i s t e n t with those of Table 1 r e p o r t i n g on the economic c o s t s of va r i o u s g e n e r a t i o n p r o j e c t s . A f t e r removing 6 3 The suggested 15-85 demand-energy s p l i t f o r l a r g e customers i n the energy c r i t i c a l B.C. Hydro system appears c o n s i s t e n t with the f i n d i n g t h a t the r e l e v a n t demand-energy s p l i t f o r l a r g e customers i n the c a p a c i t y c r i t i c a l O n t a r i o Hydro system should be changed from 50-50 to 35-65. (Ontario Hydro, 1976, V o l . 1,17) 95 the costs associated with "miscellaneous investment plant", the analysis i n t h i s section indicates an average marginal energy cost f o r a l l customers of 18.5 m i l l s per KWH. This compares with a short run marginal energy cost of 18.7 m i l l s from generating energy at Burrard. In the longer run, disregarding the diversion p r o j e c t s , 6 * Revelstoke energy i s to cost 14 m i l l s per KWH while a l l subsequent energy producing projects w i l l cost 17-19 m i l l s . The capacity related component of costs also seems reasonable. Table 1 suggests the costs of peaking projects (excluding gas turbines) are between $7.00 and $15.00 a kilowatt. This compares with the marginal cost estimates of $18.00 and $26.00 for large and small customers respectively. The difference i s accounted for by the additional peak-related costs associated with the relevant downstream transmission, transformation and d i s t r i b u t i o n f a c i l i t i e s . Lastly, we compare the average accounting costs of Table 2 with the marginal economic costs of Table 5. The former increase from 18 to 19 m i l l s per KWH i n the period 1976-1990, while the l a t t e r average 24 mills for the system as a whole. The purpose, methodology and assumptions underlying the derivation of these two r e s u l t s i s quite d i f f e r e n t and there i s no 'a p r i o r i 1 reason why the numbers should be s i m i l a r . Nevertheless, there i s some reason to believe that the two figures are, i n f a c t , reasonably consistent. 6 * The diversion projects should not be considered as marginal sources of enerqy. They are r e l a t i v e l y small and low cost, and are now being constrained by non-economic considerations. These projects are l i k e l y to be brought on stream as soon as i n s t i t u t i o n a l l y possible, and at l e a s t i n the case of the Kootenay River Diversion, regardless of the energy supply-demand balance. 96 The Table 2 r e s u l t s are average, not marginal, accounting c o s t s expressed i n 1976 m i l l s per KWH. The e x i s t e n c e of a s l i g h t i n c r e a s e i n these average c o s t s d u r i n g t h i s p e r i o d suggests t h a t marginal accounting c o s t s exceed average accounting c o s t s . T h i s s l i g h t i n c r e a s e i s i n s p i t e of the c o n s t r u c t i o n of s e v e r a l r e l a t i v e l y i n e x p e n s i v e " n o n - i a r g i n a l " d i v e r s i o n p r o j e c t s which tend to lower average c o s t s . I t i s a l s o i n s p i t e of the tendency f o r the average accounting c o s t of the o l d e r c a p i t a l - i n t e n s i v e p r o j e c t s to f a l l i n r e a l terms duri n g periods of i n f l a t i o n , suggesting f u r t h e r t h a t the r e a l u n i t cost of new p r o j e c t s must be above average accounting c o s t s . We conclude t h i s s e c t i o n by n o t i n g t h a t the marginal economic c o s t s presented i n Table 5 seem c o n s i s t e n t with an i n t u i t i v e understanding of the o p e r a t i o n o f the B.C. Hydro system, the economic c o s t i n g of p o s s i b l e new g e n e r a t i o n p r o j e c t s shown i n Table 1, and the average system accounting c o s t s c a l c u l a t e d i n the p r e v i o u s s e c t i o n . We now turn our a t t e n t i o n to the a p p l i c a t i o n and i m p l i c a t i o n s of these marginal c o s t s . 97 6-. APPLICATIONS In t h i s c hapter, we apply the marginal economic c o s t s d e r i v e d i n Chapter 5 and study the i m p l i c a t i o n s f o r the B.C. Hydro system of t h i s change. The f i r s t s e c t i o n d i s c u s s e s the a p p l i c a t i o n o f economic p r i n c i p l e s to the design of a r a t e s t u c t u r e - both i n g e n e r a l and as i t c o u l d apply to B.C. Hydro. The second e x p l a i n s how the impact on system expansion and c o s t s of a reformed r a t e s t r u c t u r e can be determined, and p r e s e n t s v a r i o u s r e s u l t s from such a r e s t r u c t u r i n g . 6.J. Rate S t r u c t u r e Design 6.1.1 General The fundamental o b j e c t i v e i n d e s i g n i n g an e c o n o m i c a l l y - e f f i c i e n t r a t e s t r u c t u r e i s to equate marginal economic p r i c e and c o s t , while keeping average accounting p r i c e equal to averaqe accounting c o s t . F i g u r e 1 r e p r e s e n t s a t y p i c a l r e s i d e n t i a l r a t e s t r u c t u r e . A customer consuming x k i l o w a t t - hours per month f a c e s a marginal r a t e o f y c e n t s per KWH and pays a t o t a l b i l l i n d i c a t e d by the shaded "L" which i s assumed to egual the accountinq c o s t s i n c u r r e d to serve him. I f the marqinal economic c o s t i s found to be z cents per KWH, then the marginal r a t e should be set equal t o t h i s and the r a t e s t r u c t u r e desiqned t o ensure t h a t the area beneath the r a t e curve (revenue) equals the shaded *'L". I n t h i s simple example, a f l a t Y6 FIGURE 1 • /KWH C -7?- B D T I E_ X KWH/MO 99 r a t e of z cents per KWH f o r a l l consumption would s a t i s f y both c o n d i t i o n s s i n c e ABCD= DEFG which i m p l i e s ABESHI=CFHI. The d i f f i c u l t y a r i s e s when these two c r i t e r i a are not as e a s i l y r e c o n c i l e d . Those who hold f i r m to the economic e f f i c i e n c y c r i t e r i o n tend t o support e i t h e r a m u l t i - p a r t or m u l t i - b l o c k approach. The former a d j u s t s the l e a s t p r i c e s e n s i t i v e component of the t o t a l b i l l ( u s u a l l y the customer or f i x e d charge) so as to meet the revenue o b j e c t i v e . The l a t t e r m o d i f i e s the " i n t r a - marginal" consumption r a t e (a cents per KWH i n Figure 1), w i t h i n the bounds of the customer's consumer s u r p l u s , to a g a i n meet the accounting c o n d i t i o n . Others abandon the s t r i c t economic e f f i c i e n c y o b j e c t i v e , a l l o w i n g the marginal p r i c e to d e v i a t e from the marginal economic c o s t . T h i s may be done on the b a s i s of the " i n v e r s e e l a s t i c i t y r u l e " whereby the amount of the d e v i a t i o n i s i n v e r s e l y p r o p o r t i o n a l t o the p r i c e e l a s t i c i t y . A l t e r n a t i v e l y , a s t r a i g h t " a c r o s s the board" adjustment i n marginal p r i c e s so as to be c o n s i s t e n t with the revenue reguirement i s sometimes recommended. We turn now to examine the s p e c i f i c case of B.C. Hydro and to suggest f a c t o r s to be i n c o r p o r a t e d i n an optimal r a t e s t r u c t u r e . We s h a l l seek not t o d e v i a t e from the s t r i c t equating of marqinal economic c o s t s and p r i c e s i n our attempt to s a t i s f y the fundamental o b j e c t i v e o u t l i n e d at the o u t s e t . 6.1.2 B.C. Hydro In suggesting an a p p r o p r i a t e r a t e s t r u c t u r e , we s h a l l use the marginal economic c o s t s c a l c u l a t e d i n the l a s t c h a p t e r . 100 Average e x i s t i n g p r i c e s i n each customer c l a s s w i l l be taken to represent the a p p r o p r i a t e average accounting c o s t s . 6 5 R e s i d e n t i a l customers as a c l a s s have a c o i n c i d e n t l o a d f a c t o r of between 45 and 50 percent and are b i l l e d on the b a s i s of the amount of energy they use each p e r i o d . 6 6 In order to use the f i g u r e s shown i n T a b l e 5, we must a d j u s t upwards the 4.6 m i l l s per KWH c a p a c i t y charge f o r s m a l l customers t o r e f l e c t t h i s reduced l o a d f a c t o r . The r e s u l t i n g combined energy and c a p a c i t y marginal economic c o s t i s 2 6 m i l l s per KWH. T h i s compares with an average accounting c o s t of 28 m i l l s per KWH. T h i s suggests t h a t the a p p r o p r i a t e r a t e s t r u c t u r e would be a f l a t r a t e of 2.6 c e n t s per KWH f o r a l l u n i t s of energy consumed. The a d d i t i o n a l .2 cents per KWH could be obtained through a s m a l l customer c h a r g e . 6 7 T h i s i s i n c o n t r a s t to the e x i s t i n g high p r i c e d i n i t i a l block f o l l o w e d by a 1977 marginal r a t e of 1.8 c e n t s per KWH (in 1976$). Bulk customers, on the other hand, are b i l l e d with s e p a r a t e charges f o r t h e i r energy and peak requirements. As a c l a s s , they have a c o i n c i d e n t l o a d f a c t o r of approximately 82 p e r c e n t . 6 8 Table 5 i n d i c a t e s t h a t they s h o u l d face a marginal energy charge 6 5 as mentioned i n Chapter 2, B.C. Hydro accounts suggest t h a t each customer c l a s s i s now g e n e r a t i n g revenue which approximately meets the accounting c o s t s a t t r i b u t e d to i t . In t h i s paper, we w i l l accept the present a l l o c a t i o n of c o s t s between customer c l a s s e s . a s t r o n g argument can be made, however, t h a t the c o s t a l l o c a t i o n methodology, with i t s heavy emphasis on the c a p a c i t y component, undercharges customers with high load f a c t o r s . 6 6 T h i s load f a c t o r appears to be r e l a t i v e l y constant a c r o s s a l l l e v e l s of consumption w i t h i n the c l a s s . 6 7 U n l i k e the present s i t u a t i o n , t h i s customer charge could r e f l e c t c o s t d i f f e r e n c e s i n s e r v i n g v a r i o u s customer types and d e n s i t i e s . 6 8 T h i s i s a l s o r e l a t i v e l y independent of the q u a n t i t y consumed. 10 1 of 19 m i l l s and an adjusted marginal c a p a c i t y charge of 3 m i l l s per KWH ($18.00 per KW) . A t present, they are charged 4 and 6 m i l l s r e s p e c t i v e l y f o r an average p r i c e of approximately 10 m i l l s per KWH.69 Our r e s u l t s i n d i c a t e a s u b s t a n t i a l r e s t r u c t u r i n g of the r a t e schedule f o r t h i s customer c l a s s i s i n o r d e r . In a d d i t i o n to a dramatic r e v e r s a l of the demand-energy s p l i t , 7 0 the combined recommended marginal energy and c a p a c i t y r a t e i s more than double that r e q u i r e d to meet revenue reguirements f o r the c l a s s . T h i s g i v e s r i s e t o the t r a d i t i o n a l dilemma on the r e c o n c i l i a t i o n of the two c o n s i d e r a t i o n s . One way to deal with t h i s would be to charge the two marginal r a t e s as f l a t r a t e s f o r a l l l e v e l s of consumption and then provide an annual c r e d i t on the b a s i s o f the consumption l e v e l a t an i n i t i a l r e f e r e n c e p o i n t . 7 1 In t h i s way, the h i s t o r i c a l b e n e f i t s would be r e t u r n e d t o customers while at the same time they would face the a p p r o p r i a t e marginal p r i c e s f o r any changes i n t h e i r l e v e l of consumption. In the case of g e n e r a l customers, the combined energy and c a p a c i t y charqes should approximate 24 m i l l s per KWH. T h i s i s e q u i v a l e n t to the present average p r i c e f o r the c l a s s , so t h a t a 6 9 The peak charge now i n e f f e c t and t h a t recommended are not d i r e c t l y comparable. I t i s c u r r e n t l y based on the customer's non-coincident peak, w h i l e we suggest that i t should be determined l a r g e l y on the b a s i s of the degree of c o i n c i d e n c e with the system's peak. 7 0 T h i s i s the term used i n the e l e c t r i c u t i l i t y i n d u s t r y to r e f e r to the s p l i t between the peak and energy components of e l e c t r i c a l demand. , 7 1 New l a r g e customers c o u l d a l s o be given a r i g h t to the revenue s u r p l u s f o r t h e i r c l a s s by r e c e i v i n g a s i m i l a r annual c r e d i t based on what a comparable f i r m consumed a t the i n i t i a l r e f e r e n c e p o i n t . T h i s consumption l e v e l e s t a b l i s h e s the s i z e of each customer's claim on each year's s u r p l u s . 102 new f l a t r a t e at t h i s l e v e l would r e g u i r e l i t t l e adjustment to r e c o n c i l e the economic and accounting c r i t e r i a . However, w i t h i n the c l a s s , i t would i n v o l v e a r e d u c t i o n i n the b i l l s f o r the l a r g e number of s m a l l customers at the expense of the s m a l l number of l a r g e r e l e c t r i c i t y u s e r s . 7 2 There are a number of other c o n s i d e r a t i o n s which c o u l d enter i n t o the design of an a p p r o p r i a t e r a t e s t r u c t u r e . Many j u r i s d i c t i o n s are c o n s i d e r i n g time of day r a t e s . T h i s f a c t o r i s not as r e l e v a n t i n the e n e r g y - c r i t i c a l B.C. Hydro system where a k i l o w a t t - h o u r consumed at 5 a.m. reduces the annual energy c a p a b i l i t y by the same amount as one used at 5 p.m. Nevertheless, to the extent that p e t r o l e u m - f i r e d p l a n t s are needed to meet peak demand and t h a t downstream f a c i l i t i e s are c a p a c i t y - r e l a t e d , some d i u r n a l r a t e v a r i a t i o n s may y i e l d a net economic b e n e f i t . 7 3 A worthwhile i n i t i a l step would be to make the peak charge f o r l a r g e customers g r e a t e s t when i t c o i n c i d e d with the system's peak, r a t h e r than having i t s d e t e r m i n a t i o n independent of t h i s peak. A more important t i m e - v a r y i n g r a t e , and one which c o u l d be i n t r o d u c e d r e l a t i v e l y e a s i l y , i s the s e a s o n a l t a r i f f . B.C. Hydro's annual peak i s i n the winter, a time when stream flow i s at a minimum. Hence r e s e r v o i r s must be designed so t h a t they w i l l not empty, once f i l l e d i n the summer, during the winter p e r i o d . At the same time, downstream f a c i l i t i e s must be b u i l t t o 7 2 A f u l l e r d i s c u s s i o n of p o s s i b l e r a t e s t r u c t u r e d e s i g n s , i n c l u d i n g some g u a n t i f i c a t i o n o f the impact o f these changes, i s contained i n Appendix C. 7 3 N a t u r a l l y , any move e n t a i l i n g i n s t a l l a t i o n of new eguipment to make t h i s f e a s i b l e should only be undertaken i f the r e s u l t i n g marginal economic b e n e f i t exceeds the marginal c o s t i n v o l v e d . 103 meet the system's winter peak, and the p e t r o l e u m - f i r e d U n i t s are most l i k e l y to be r e q u i r e d i n t h i s season, both to meet peak requirements and to f u l f i l f o r e c a s t annual energy d e f i c i e n c i e s . Sates which r e f l e c t e d the higher p l a n n i n g and o p e r a t i n g c o s t s a s s o c i a t e d with the winter peak would enable some customers t o a l t e r t h e i r seasonal consumption p a t t e r n s o r switch to an energy source which was l e s s s e a s o n a l l y s e n s i t i v e . A r e l a t e d approach with a p p l i c a b i l i t y to B.C. Hydro i s a t a r i f f which v a r i e d a c c o r d i n g to water c o n d i t i o n s . As we have seen, the d r i e r the year, the g r e a t e r B.C. Hydro's r e l i a n c e upon expensive thermal s o u r c e s . Higher r a t e s d u r i n g dry years would encourage some customers to b u i l d and u t i l i z e a l t e r n a t i v e energy sources with long term storage c a p a b i l i t y when t h i s proved to be to t h e i r economic advantage. Co n v e r s e l y , during wet years, water that would have s p i l l e d over the dams cou l d be u t i l i z e d by customers t a k i n g advantage of low r a t e s that year. The i n t r o d u c t i o n of i n t e r r u p t i b l e r a t e c l a s s e s with v a r y i n g expected frequency and d u r a t i o n of i n t e r r u p t i o n might be a u s e f u l way to i n d i c a t e these seasonal and annual c o s t v a r i a t i o n s to the l a r g e customers. Another c o n s i d e r a t i o n which c o u l d be i n c o r p o r a t e d i n the design of a r a t e s t r u c t u r e i s the co s t asymmetry between demand i n c r e a s e s and decreases. A l a r g e aggregate r e d u c t i o n i n demand would i n i t i a l l y e l i m i n a t e the cost of f u e l a t Burrard but would then e f f e c t few cost savings due t o the l a r g e f i x e d c o s t s a s s o c i a t e d with the system. I f an aggregate decrease i n demand was a n t i c i p a t e d from the i n i t i a l design of a r a t e s t r u c t u r e , m o d i f i c a t i o n s c o u l d be i n t r o d u c e d which reduced the marginal 104 r a t e once a customer had cut back h i s demand by a c e r t a i n amount. I f , however, a r e d u c t i o n i n the t o t a l demand l e v e l was not expected, then the higher r a t e c o u l d be maintained to provide those with the f l e x i b i l i t y the chance to a d j u s t t h e i r consumption and thus slow the r a t e of growth i n system demand. A r e l a t e d c o n s i d e r a t i o n i s the a p p r o p r i a t e timing of r a t e s t r u c t u r e reform. Given t h a t new hydro p r o j e c t s are c u r r e n t l y under c o n s t r u c t i o n and w i l l be coming on stream, the sudden i n t r o d u c t i o n of an economically e f f i c i e n t r a t e s t r u c t u r e could cut demand below what would be saved at Burrard i n f u e l c o s t s , and provide a s m a l l e r base from which t o cover the l a r g e f i x e d c o s t s . A b e t t e r approach would be t o g i v e f i v e or s i x years n o t i c e of a change i n r a t e s t r u c t u r e (or move there g r a d u a l l y ) , so that p r o j e c t s not yet approved c o u l d be d e f e r r e d while those underway would f i n d a market f o r t h e i r output once completed. The t i m i n g of the i n t r o d u c t i o n of a reformed rate s t r u c t u r e and the a p p r o v a l of new g e n e r a t i o n p r o j e c t s are i n e v i t a b l y i n t e r t w i n e d and must be c a r e f u l l y o r c h e s t r a t e d . 6.2 Demand And System Response 6.2.1 Theory Rate s t r u c t u r e reform c o n s i s t e n t with p r i n c i p l e s of economic e f f i c i e n c y w i l l a f f e c t the demand f o r e l e c t r i c i t y and thus a l t e r system p l a n n i n g , o p e r a t i o n and u l t i m a t e l y , c o s t s . The present B.C. Hydro l o a d f o r e c a s t s i m p l i c i t l y assume no change i n the e x i s t i n g r a t e s t r u c t u r e . Thus, we are i n t e r e s t e d i n the 105 impact on demand and c o s t s of i n t r o d u c i n g the marginal p r i c e s d i s c u s s e d i n the l a s t s e c t i o n . 7 * The demand f o r e l e c t r i c i t y depends upon a number of f a c t o r s i n c l u d i n g p o p u l a t i o n and income l e v e l s , weather, i t s own marginal p r i c e and the p r i c e and a v a i l a b i l i t y of s u b s t i t u t e energy forms. In the case o f an i n d u s t r i a l user, e l e c t r i c i t y r e p r e s e n t s one of many i n p u t s r e g u i r e d to produce i t s output. A p r o f i t maximizing f i r m i s assumed to seek to combine these i n p u t s i n a manner which w i l l minimize c o s t s f o r a given l e v e l of output, s u b j e c t to the p r o d u c t i o n f u n c t i o n d e f i n i n g the most e f f i c i e n t t e c h n i c a l p o s s i b i l i t i e s f a c i n g i t . A consumer, on the other hand, i s assumed to d e r i v e s a t i s f a c t i o n from consumption, i n c l u d i n g the use of f a c i l i t i e s r e q u i r i n g e l e c t r i c i t y , and t o seek t o maximize t h i s s a t i s f a c t i o n s u b j e c t to a budget c o n s t r a i n t l i m i t i n g the combination and q u a n t i t y of items a v a i l a b l e to him. When the marginal p r i c e of e l e c t r i c i t y i n i t i a l l y r i s e s , only a l i m i t e d number of p o s s i b i l i t i e s to reduce i t s consumption are a v a i l a b l e . In the medium term, however, c a p i t a l s t o c k can be a l t e r e d and the f a c t o r mix a d j u s t e d . In the l o n g term, new, more e l e c t r i c i t y - c o n s e r v i n g technology can be developed and l i f e s t y l e s can be changed. We seek a means to g u a n t i f y the e f f e c t over time of t h i s change i n marginal p r i c e , due s o l e l y to r a t e s t r u c t u r e reform, when a l l other i n p u t p r i c e s and output 7 4 I t should be r e i t e r a t e d t h a t we are concerned here with a change i n r a t e s t r u c t u r e , not l e v e l . We assume that B.C. Hydro's f o r e c a s t s have taken i n t o account a n t i c i p a t e d changes i n r a t e l e v e l s , and we seek now to examine the impact o f a l t e r i n g r a t e s t r u c t u r e given a r a t e l e v e l . In the l o n g e r term, r a t e s t r u c t u r e reform w i l l a l s o a f f e c t r a t e l e v e l s . 106 l e v e l s remain unchanged. The long run arc own p r i c e e l a s t i c i t y of the demand f o r e l e c t r i c i t y enables us t o do j u s t t h a t . I t measures the average change i n e l e c t r i c i t y consumed r e l a t i v e t o the average change i n p r i c e , a l l other f a c t o r s remaining c o n s t a n t . A l g e b r a i c a l l y , e = ((Q2 - Q1)/(Q1 • Q2)} / { (P2 - P1)/(P1 + P2)) ......(12) where e i s the long run arc own p r i c e e l a s t i c i t y and i s l e s s than or egual to 0; Q1 i s the o r i g i n a l consumption l e v e l ; Q2 i s the new consumption l e v e l a f t e r the p r i c e change; P1 i s the o r i g i n a l r e a l marginal p r i c e ; and P2 i s the new r e a l marginal p r i c e . Rearranging and using the a b s o l u t e value of e, Q2 = Q1 * (P1 + P2 - e * (P2 - P1}) / (P1 + P2 + e * (P2 - P1)) (13) Hence the long term adjustment to Q2 from Q1 as a r e s u l t of a r e a l marginal p r i c e i n c r e a s e from P1 to P2 can be determined given an a p p r o p r i a t e value f o r e and some assumption about the adjustment process. For an i n d i v i d u a l consumer, i t i s c o n v e n t i o n a l t o c o n s i d e r both income and s u b s t i t u t i o n e f f e c t s of a p r i c e change. In the present case, however, s i n c e we have a l t e r e d only the marginal p r i c e and have l e f t the average p r i c e unchanged, the income e f f e c t i s l i k e l y to be n e g l i g i b l e . T h e r e f o r e i t i s i g n o r e d . S i m i l a r l y , f o r an i n d u s t r i a l consumer, the p r i c e e f f e c t i s 107 assumed to take place along a given isoguant, and thus output e f f e c t s are not c o n s i d e r e d . The a r c , r a t h e r than p o i n t , e l a s t i c i t y i s used because i t enables us t o more a c c u r a t e l y estimate the q u a n t i t y adjustment from a r e l a t i v e l y l a r g e marginal p r i c e change..Nevertheless, care must be e x e r c i s e d i n the use of the e l a s t i c i t y estimates f o r very l a r g e p r i c e changes because of the i n e v i t a b l e n o n - l i n e a r i t y of the demand curve. 6.2.2 Modelling In order to examine the i m p l i c a t i o n s of r a t e s t r u c t u r e reform, s e v e r a l new f e a t u r e s must be i n t r o d u c e d to the model d e s c r i b e d i n Chapter 4. C o e f f i c i e n t s are used t o read i n the o l d marginal r a t e s of 17,15 and 10 m i l l s per KWH and the new marginal r a t e s of 26, 24, and 22 m i l l s f o r r e s i d e n t i a l , g e n e r a l and bulk customers r e s p e c t i v e l y . Each c l a s s i s a l s o assigned a long run own p r i c e e l a s t i c i t y . Equation (13) i s then used, given P1, P2, Q1, and e, t o determine the r e v i s e d Q2 f o r the c u r r e n t year and that s i x years hence f o r each customer c l a s s . The new r a t e s t r u c t u r e i s assumed to be f u l l y implemented i n 1981, and each year between 1977 and 1981 sees o n e - f i f t h of the u l t i m a t e consumption adjustment take p l a c e . The choice of a p p r o p r i a t e e l a s t i c i t y c o e f f i c i e n t s i s as d i f f i c u l t as i t i s important. An o u t s i d e study commissioned by B.C. Hydro estimated long run own p r i c e e l a s t i c i t i e s of -0.35 f o r r e s i d e n t i a l customers and from -1.0 to -2.3 f o r non- r e s i d e n t i a l customers, using monthly data f o r 5 r e g i o n s d u r i n g the 1964-1972 p e r i o d (Wilson, 1974). Other s t u d i e s tend t o suggest somewhat higher r e s i d e n t i a l e l a s t i c i t i e s and somewhat 108 lower n o n - r e s i d e n t i a l f i g u r e s . Table 6 presents the r e s u l t s of var i o u s estimates of l o n g run own p r i c e e l a s t i c i t i e s by customer TABLE 6 A SURVEY Of ESTIMATED LONG RUN OWN PRICE ELASTICITIES OF ELECTRICITY DEMAND R e s i d e n t i a l Anderson(1973) -1.12 F e d e r a l Energy A d m i n i s t r a t i o n (1976) -1.46 F i s h e r and Kaysen(1962) 0.0 G r i f f i n { 1 9 7 4 ) -0.52 Halvorsen(1973) -0 . 9 7 Houthakker and Taylor(1970) -1.89 Houthakker, Verl e g e r and Sheehan(1973) -1.02 Mount, Chapman and T y r r e l l (1973) -1.20 T a y l o r , B l a t t e n b e r g e r and Verleger{1976) -0.78 Uri(1975) -1.66 Wilson{1971) -2.00 Wilson{1974) -0. 18 -0.35 Wilson<1974a) -0.406 Commercial F e d e r a l Energy A d m i n i s t r a t i o n ( 1 9 7 6 ) - 0 . 3 8 G r i f f i n ( 1 9 7 4 J - 0 . 5 1 H a l v o r s e n ( 1 9 7 3 ) - 0 . 9 1 Mount, Chapman and T y r r e l l ( 1 9 7 3 ) - 1 . 3 6 U r i ( 1 9 7 5 ) - 0 . 8 5 W i l s o n { 1 9 7 4 ) - 1 . 0 - 2 . 3 I n d u s t r i a l Anderson (1973) -1.94 Baxter and Rees(1968) -1.50 F e d e r a l Energy A d m i n i s t r a t i o n (1976) -0. 15 F i s h e r and Kaysen(196 2) -1.25 G r i f f i n ( 1 9 7 4 ) -0.51 Halvorsen(1973) -1.24 Mount, Chapman and T y r r e l l ( 1 9 7 3 ) -1.82 Uri(1975) -0.35 Wilson{1971) -1.33 Wilson{1974) -1.2 -2.3 109 c l a s s . 7 s As a base case, we s h a l l use a b s o l u t e value estimates of .4, .6 and .8 f o r r e s i d e n t i a l , g e n e r a l and i n d u s t r i a l c l a s s e s r e s p e c t i v e l y . 7 6 S e n s i t i v i t y a n a l y s i s using .2, .*», and .6 a t the low end and .7, .8 and 1.2 at the high end w i l l a l s o be r u n . The i n c r e a s e i n the r e a l marginal p r i c e f o r both r e s i d e n t i a l and general customers i s i n the order of 50 percent, whereas i t exceeds 100 percent f o r the bulk customers. The magnitude of t h i s l a t t e r i n c r e a s e suggests t h a t a reduced c o e f f i c i e n t be used to r e f l e c t the n o n - l i n e a r i t y i n the demand curve which may become important f o r t h i s l a r g e an i n c r e a s e . However, i n going from 10 to 22 m i l l s , we d i s g u i s e the f a c t t h a t the energy r a t e i s recommended to i n c r e a s e from 3 to 19 m i l l s . Given t h a t the stock of e l e c t r i c i t y consuming eguipment i s l i k e l y t o be p r i m a r i l y a f f e c t e d by the energy charge, the use of the i n i t i a l combined r a t e of 10 m i l l s w i l l tend to underestimate the impact of the i n c r e a s e . We t h e r e f o r e use the f u l l e l a s t i c i t y 7 5 These r e s u l t s are presented to give an i n d i c a t i o n o f the range of e l a s t i c i t y e s t i m a t e s t h a t have been observed. Co n s i d e r a b l e v a r i a t i o n i n the methodology of the u n d e r l y i n g s t a t i s t i c a l a n a l y s i s , p a r t i c u l a r l y as regards the p r i c e of e l e c t r i c i t y , makes some of these s t u d i e s more r e l e v a n t than others f o r the purposes of t h i s paper. 7 6 The estimates f o r bulk customers may i n f a c t be too low given t h e i r tendency to ignore the l a r g e p o t e n t i a l f o r e l e c t r i c a l s e l f - g e n e r a t i o n by some i n d u s t r i a l users i n B.C. Were the economic i n c e n t i v e s present, g r e a t e r use of the c u r r e n t and a n t i c i p a t e d s u r p l u s of wood waste would be made., Such s e l f - g e n e r a t i o n , with i t s l a r g e energy component ( r e l a t i v e to ca p a c i t y ) and i t s tendency to peak i n the winter months, would complement B.C. Hydro's system. The c u r r e n t low marginal r a t e f o r bulk customers, with a r e l a t i v e l y l a r g e and r a t c h e t t e d peak component, provides l i t t l e encouragement f o r the displacement of Hydro's power by that which i s s e l f - g e n e r a t e d . Moreover, the p r i c e which B.C. Hydro i s o f f e r i n g f o r s u r p l u s energy, r a i s e d r e c e n t l y to between 5 and 6 m i l l s , i s f a r below the A u t h o r i t y ' s marginal energy c o s t s and f u r t h e r discourages the i n s t a l l a t i o n of the economically a p p r o p r i a t e g u a n t i t y of s e l f - g e n e r a t i n g c a p a b i l i t y . 110 estimate on the modified p r i c e change {10 t o 22 m i l l s ) i n an e f f o r t to o f f s e t the two c o n f l i c t i n g b i a s e s . A r e l a t e d c o n s i d e r a t i o n i s the assumption we make about the impact on the system l o a d f a c t o r of the reformed r a t e s t r u c t u r e . On the one hand, the reduced peak charge f o r the bulk customers w i l l tend to reduce the customer's l o a d f a c t o r . However, a customer peak charge that was r e l a t e d t o the degree of c o i n c i d e n c e with the system's peak would tend t o improve the system's load f a c t o r . In t h i s a n a l y s i s we assume the c a n c e l l i n g out of these two opposing f o r c e s and maintain the system l o a d f a c t o r assumption of 63.5 p e r c e n t . 7 7 The new o p e r a t i n g and expansion plan a l s o p r o v i d e s a d i f f e r e n t base case from which marginal c o s t s can be determined. By c a l c u l a t i n g the impact of the same v a r i e t y o f demand shocks on t h i s base case as was undertaken i n the l a s t c h a p t e r , new estimates of marginal c o s t s can be o b t a i n e d . These r e v i s e d f i g u r e s w i l l p r o v i d e us with a b e t t e r understanding of the degree of s e n s i t i v i t y of the estimates to the base case that i s being examined. 6.2.3 Results Table 7 h i g h l i g h t s the i m p l i c a t i o n s of r a t e s t r u c t u r e reform under the assumptions o u t l i n e d i n the l a s t s e c t i o n . The r e s u l t s i n the f i r s t column assume no change i n the r a t e s t r u c t u r e and are t h e r e f o r e i d e n t i c a l t o those presented i n the l a s t chapter. The next three show the e f f e c t s of reformed r a t e 7 7 The extent to which a l t e r i n g the r e l a t i v e and a b s o l u t e energy and peak p r i c e s a f f e c t s the i n d i v i d u a l ' s and the system's l o a d f a c t o r i s an important,yet r e l a t i v e l y unstudied, area. TABLE 7 IMPLICATIONS OF RATE STRUCTURE REFORM NO RATE RATE STRUCTURE REFORM WITH STRUCTURE REFORM DIFFERENT PRICE ELASTICITY ASSUMPTIONS Low Base Case H i g h Growth Rate In Demand (%) 9„0 7.8 7.0 5 7 (1976 - 1990) A v e r a g e A c c o u n t i n g C o s t (1976 M i l l s p e r KWH) 18.1 17.1 16.5 16.1 (1976 - 1990) Gross Debt O u t s t a n d i n g In 1990 17.1 ( B i l l i o n s o f H i s t o r i c $) 13.4 11.2 10.2 112 s t r u c t u r e s under i n c r e a s i n g l y l a r g e own p r i c e e l a s t i c i t y assumptions. As would be expected, the g r e a t e r these e l a s t i c i t i e s , the lower the growth r a t e i n demand i n the 1976- 1990 p e r i o d . In f a c t , the major readjustment i n demand occurs between 1977 and 1981, with s l i g h t d e c l i n e s o c c u r r i n g i n two years under the high e l a s t i c i t i e s case. Once the new r a t e s t r u c t u r e has been f u l l y implemented, demand i s assumed to respond p r i m a r i l y to the v a r i o u s f a c t o r s i m p l i c i t i n the Task Force p r o j e c t i o n s and averages 8.5 percent i n a l l cases i n the 1982- 1990 p e r i o d . The reduced growth r a t e s d e f e r the need to develop more expensive new generation s o u r c e s , 7 8 thereby r e d u c i n g both average accounting c o s t s and investment. How two of Table 6 i s de r i v e d by t a k i n g a l l accounting c o s t s i n each year between 1976 and 1990, adding any net income, s u b t r a c t i n g any export revenue, c o n v e r t i n g the t o t a l i n t o 1976 d o l l a r s , d i v i d i n g by the g u a n t i t y of energy generated by B.C. Hydro and averaging the r e s u l t s over t h i s p e r i o d . The r e d u c t i o n i n r e a l average u n i t net accounting c o s t s ranges from 5.4 (low e l a s t i c i t i e s ) t o 11.0 percent (high e l a s t i c i t i e s ) with a value of 8.8 percent under the base case e l a s t i c i t i e s assumption. The l a s t row of the t a b l e i n d i c a t e s the a n t i c i p a t e d gross debt o u t s t a n d i n g ( a t t r i b u t a b l e t o the e l e c t r i c s e r v i c e ) of B.C. Hydro i n 1990 i n b i l l i o n s of h i s t o r i c d o l l a r s . T h i s s e r v e s as a good proxy f o r t o t a l investment d u r i n g t h i s p e r i o d s i n c e most of 7 8 These new sources are more expensive than the o l d ones both i n r e a l terms and because of the d i s t o r t i o n s of the accounting system ( p a r t i c u l a r l y during p e r i o d s of i n f l a t i o n ) d i s c u s s e d i n the l a s t chapter. 11.3 the A u t h o r i t y ' s c a p i t a l requirements w i l l continue to he met by debt f i n a n c i n q . The r e d u c t i o n i n the 1990 debt l e v e l i s 33.1 percent using the base case e l a s t i c i t i e s , with extremes of 20.4 and 38.1 percent under the a l t e r n a t i v e e l a s t i c i t y assumptions. The t a b l e a l s o r e v e a l s the e x i s t e n c e of decreasing r e t u r n s from growth r a t e r e d u c t i o n s over the 1976-1990 p e r i o d . The f i r s t one percent r e d u c t i o n i n the growth r a t e has a l a r g e r impact on average c o s t s than does the next one percent. T h i s r e s u l t s from the high p r o p o r t i o n of f i x e d c o s t s a s s o c i a t e d with the B.C. Hydro system which reduces the a t t r a c t i v e n e s s o f demand growth r e d u c t i o n s i n the f i r s t h a l f o f t h i s p e r i o d . Indeed, i t i s o n l y a f t e r 1982 t h a t the o p p o r t u n i t i e s f o r c o s t s a v i n g s r e s u l t i n g from the d i f f e r e n t growth r a t e s become p a r t i c u l a r l y a p p a r e n t . 7 9 An a n a l y s i s of marginal economic c o s t s s i m i l a r to t h a t performed i n the l a s t chapter was a l s o undertaken i n which demand shocks of from 10 t o 500 m i l l i o n KWH i n both d i r e c t i o n s and with d i f f e r e n t l o a d f a c t o r s were imposed on the f o r e c a s t using the base case demand e l a s t i c i t i e s of .4, .6 and .8. The r e s u l t s were compiled i n the same manner as those presented i n Table 5. The average combined marginal energy and c a p a c i t y c o s t f o r l a r g e customers was found to be 22.1 m i l l s per KWH using the 7.0 percent growth r a t e compared with the e a r l i e r r e s u l t of 22.6 m i l l s with the 9.0 percent r a t e of growth over the 1976-1990 p e r i o d . The energy component rose s l i g h t l y while the peak component f e l l from 3.2 to 2.4 m i l l s per KWH a t the system l o a d 7 9 A system with a g r e a t e r thermal component would d e r i v e more immediate b e n e f i t s from demand growth r e d u c t i o n s . The diminished f l e x i b i l i t y i n the B.C. Hydro case re-emphasizes the importance of c o - o r d i n a t i n g the i n t r o d u c t i o n of r a t e s t r u c t u r e reform with the a p p r o v a l of major new p r o j e c t s . 114 f a c t o r . In l i g h t of the apparent s t a b i l i t y i n the marginal c o s t e s t i m a t e s , no r e d e s i g n of r a t e s t r u c t u r e s and r e - e s t i m a t i o n of demand was deemed necessary t o r e f l e c t the new, s l i g h t l y lower, marginal economic c o s t s . 115 I - . SDH MARY AND CONCLUSIONS - The primary purpose of t h i s paper has been t o develop and apply a marginal economic c o s t i n g methodology a p p r o p r i a t e f o r the predominantly h y d r o - e l e c t r i c system of B.C. Hydro. The b a s i c approach adopted i s one whereby each component of the demand f o r e l e c t r i c i t y i s a l l o c a t e d those i n c r e m e n t a l economic c o s t s (savings) which a change i n i t s demand w i l l cause. T h i s d i f f e r s fundamentally from the technigue now employed under which the accounting c o s t s a s s o c i a t e d with i n - s e r v i c e p l a n t are s p l i t between the components o f demand according to somewhat a r b i t r a r y accounting c r i t e r i a . The two approaches a r e r e c o n c i l e d by adopting a r a t e s t r u c t u r e which equates marginal p r i c e with marginal economic c o s t while keeping average p r i c e egual to average accounting c o s t s f o r each customer c l a s s . For the l a r g e r users (both w i t h i n each c l a s s and w i t h i n the system), t h i s l e a d s to s u b s t a n t i a l l y higher marginal r a t e s from those now i n e f f e c t . In p a r t i c u l a r , the economic a n a l y s i s a t t aches f a r grea t e r weight t o the energy component of demand i n t h e e n e r g y - c r i t i c a l B.C. Hydro system than does the accounting approach. The r e s u l t s of t h i s a n a l y s i s are summarized i n Ta b l e 8. The r e d u c t i o n i n the growth r a t e i n the demand f o r e l e c t r i c i t y induced by the new marginal p r i c e s i s q u a n t i f i e d using assumptions about each customer c l a s s ' s own p r i c e e l a s t i c i t y of demand. The ensuing d e c l i n e i n c o s t s as new, more expensive p r o j e c t s are d e f e r r e d i s a l s o c a l c u l a t e d . These r e s u l t s were presented i n Ta b l e 7 and i n d i c a t e d a r e d u c t i o n of over 9 percent i n the r e a l average u n i t annual accounting c o s t s 116 and over 40 percent i n the gross debt o u t s t a n d i n g i n 1990 using the median e l a s t i c i t y e s timates over the case with no r a t e s t r u c t u r e reform. The purpose o f moving towards marginal c o s t p r i c i n g i s to enable each i n d i v i d u a l consumer and f i r m t o achieve i t s o b j e c t i v e s i n a manner which i s l e a s t c o s t l y to s o c i e t y . The s e t t i n g of the marginal p r i c e below i t s r e a l economic v a l u e and that r e g u i r e d to make an e l e c t r i c i t y - c o n s e r v i n g technology a t t r a c t i v e w i l l l e a d to economic i n e f f i c i e n c i e s . Such s u b s i d i z a t i o n of the marginal p r i c e of e l e c t r i c i t y cannot be i n s o c i e t y ' s l o n g term best i n t e r e s t s . The r e l e v a n c e of these concerns i s now being r e c o g n i z e d by many e l e c t r i c u t i l i t i e s . Some are moving t o reform t h e i r r a t e s t r u c t u r e s a c c o r d i n g l y . The s i t u a t i o n can be p a r t i c u l a r l y acute with predentinatly h y d r o - e l e c t r i c u t i l i t i e s where recovery of the l a r g e f i x e d c o s t s i s o f t e n sought through high charges on i n i t i a l consumption b l o c k s . T h i s l e a d s to the l a t t e r b l o c k s being p r i c e d w e l l below c u r r e n t marginal economic c o s t s . There i s some evidence o f a r e c o g n i t i o n of these concerns w i t h i n B.C. Hydro. The moves towards f l a t t e r r a t e s t r u c t u r e s and i n c r e a s e d energy charges are c l e a r l y i n the r i g h t d i r e c t i o n . l e t a r e c e n t statement by the Chairman of the a u t h o r i t y (Bonner, 1977), i n d i c a t i n g t h a t the " i d e a l " r a t e s t r u c t u r e would have a very l a r g e f r o n t end charge with the balance being c o l l e c t e d by a f l a t energy charge, i s at odds with the economic p r i n c i p l e s o u t l i n e d i n t h i s paper. Indeed, there does not now appear to be any s t r o n g p o l i t i c a l or s e n i o r management committment to reform r a t e s t r u c u t e s i n accordance with the o b j e c t i v e of economic TABLE 8 MARGINAL AND AVERAGE PRICES OF ELECTRICITY (1977^/KWH) CUSTOMER CLASS MARGINAL AVERAGE EXISTING PROPOSED EXISTING/PROPOSED (as o f May 3 1977) Peak Energy Peak Energy Peak and Energy „ . . * . , .8 2.0 R e s i d e n t i a l v^^, 2.0 2.8 3.1 .6 2.0. 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T a y l o r , L e s t e r D., G.R. B l a t t e n b e r g e r , and P.K. V e r l e g e r , J r . (1976), The R e s i d e n t i a l Demand f o r Energy: Report t o the E l e c t r i c Power Research I n s t i t u t e , mimeo, June, 1976. T r e b i n g , Harry H. (ed.) (1973), Essays on P u b l i c U t i l i t y P r i c i n g and R e g u l a t i o n , Michigan State U n i v e r s i t y , East Lansing, Michigan. I r o x e l , Emery (1947), Economics of P u b l i c U t i l i t i e s , R i n e h a r t and Company, Inc., New York. Turvey, Ralph (1968), Optimal P r i c i n g and Investment i n E l e c t r i c i t y Supply, George A l l e n and Unwin, L t d . , London. Turvey, Ralph (1971), Economic A n a l y s i s and P u b l i c E n t e r p r i s e s . George A l l e n and Unwin L t d . , London. Turvey, Ralph (1976), " A n a l y z i n g the Marginal Cost of Water Supply", i n Land Economics, V o l . 52, No. 2, May, 1976. Tussing, A r l o n R. (1976), "An I n k l i n g of the Long Journey", Northern P e r s p e c t i v e s , V o l . 4. No. 4. U.S.A., O f f i c e o f U t i l i t i e s Programs, F e d e r a l Energy A d m i n i s t r a t i o n (1975), The Challenge of Load Management: A Convergence of D i v e r s e I n t e r e s t s , C o n s e r v a t i o n Paper No. 24, Washington, D.C, June, 1975. U r i , Noel D. (1975), Towards an E f f i c i e n t A l l o c a t i o n o f E l e c t r i c a l Energy; An Essay i n A p p l i e d Welfare Economics, Lexington Books, Toronto. Weisbeck, Don (1976), "A M e t h o d o l o g i c a l and Cost Comparison of A l t e r n a t i v e Analyses of E x p l o i t i n g Canadian and U.S- F r o n t i e r N a t u r a l Gas Resources", M.A. T h e s i s , Department of Economics, U n i v e r s i t y of B r i t i s h Columbia, Vancouver, September, 1976. Weitzman, Martin L. (1976), "The Optimal Development of Resource Pools", J o u r n a l of Economic Theory, V o l . 12, No. 3, June, 1976. 126 Menders, J.T.,(1976), "Peak Load P r i c i n g i n the E l e c t r i c U t i l i t y I n d u s t r y " , The B e l l J o u r n a l of Economics, V o l . 7. No. 1, Sp r i n g , 1976. Menders, John T. and L.D. T a y l o r (1976), Experiments i n Seaspnal-Time-of-Day P r i c i n g of E l e c t r i c i t y t o R e s i d e n t i a l Users, mimeo. U n i v e r s i t y of A r i z o n a . Wilson, J.W. (1971), " R e s i d e n t i a l Demand f o r E l e c t r i c i t y " , Q u a r t e r l y Review of Economics and Business, V o l . 11, No. 1, Sp r i n g , 1971. Wilson, John A. (1974), " E l e c t r i c U t i l i t y Rates and Future Power Demand Trends i n B r i t i s h Columbia: A Study Prepared f o r the B.C. Hydro and Power A u t h o r i t y " , mimeo. Wilson, H.W. (1974a), " E l e c t r i c i t y Consumption: Supply Requirements, Demand E l a s t i c i t y and Rate Design", American J o u r n a l of A g r i c u l t u r a l Economics. May, 1974. APPENDIX A B.C. HYDRO AND POWER AUTHORITY STATEMENT OF INCOME FOR THE YEAR ENDED 31 MARCH 1976 Gross r e v e n u e s , e x c l u d i n g P r o v i n c i a l Government s p e c i a l s u b s i d y $ 492,163,490 Ex p e n s e s : S a l a r i e s , wages and employee b e n e f i t s M a t e r i a l s and s e r v i c e s G r a n t s , s c h o o l t a x e s and w a t e r r e n t a l s D e p r e c i a t i o n I n t e r e s t on debt L e s s - I n t e r e s t c h a r g e d t o c o n s t r u c t i o n 213,390,701 157,000,822 102,342,574 39,531 ,674 72,779,127 61 ,578,833 151 ,811,868 523,466,065 Income ( l o s s ) b e f o r e P r o v i n c i a l Government s p e c i a l s u b s i d y (31,302,575) P r o v i n c i a l Government s p e c i a l s u b s i d y 32,600,000 Net Income $ 1,297,425 I £8 QUEEN CHARLOTTE ISLANDS British Columbia Hydro and Power Authority Electric Transmission System at 31 March 1977 with planned additions LEGEND H Hydroelectric Generating Stations • Diesel-Electric Generating Stations Gas-Turbine-Electric Generating Stations Substations Transmission Lines 60 kV-360 kV ' (existing and under construction) i Transmission Lines 500 kV (existing and under construction) Transmission Lines 60 kV-360 kV (planned) i Transmission Lines 500 kV (planned) Vancouver Area MAJOR GENERATING PLANTS Alouette: Hydroelectric Port Mann: Gas-Turbine Burrard: Steam-Turbine Ruskin: Hydroelectric Lake Buntzen: Hydroelectric Stave Falls: Hydroelectric MAJOR SUBSTATIONS Arnott Dal Grauer Horne-Payne Ingledow Kidd, Nos. 1 and 2 Mainwaring Meridian Murrin Newell Walters Horsey Prince George Williston ALBERTA 129 £ i APPENDIX C / T h i s appendix seeks to serve two purposes. The f i r s t i s to update the b a s i c r e s u l t s from the t e x t using a more r e c e n t e l e c t r i c a l demand f o r e c a s t by B . C . Hydro. The second i s to d i s c u s s a l t e r n a t i v e ways of reforming the r a t e s t r u c t u r e and to analyse some of the i m p l i c a t i o n s a s s o c i a t e d with each of them. The main t e x t of t h i s paper presented r e s u l t s based upon the e l e c t r i c a l demand f o r e c a s t given i n the May 1975 Task Force fleport. The f o r e c a s t e d average annual compound growth r a t e was 9.3 percent over the 1975-1990 p e r i o d , or 9.0 percent dur i n g the 1976-1990 p e r i o d (see Table 7). In September 1976, B . C . Hydro produced a new f o r e c a s t which, using the same 1976 base, y i e l d e d a 1976-1990 average annual growth r a t e of 8.1 p e r c e n t . 8 0 T h i s new f o r e c a s t continued to assume no r a t e s t r u c t u r e reform, but did r e f l e c t reduced e x p e c t a t i o n s about economic a c t i v i t y i n the province during these years. The i m p l i c a t i o n s f o r average r e a l u n i t accounting c o s t s and gross outstanding debt i n 1990 are i n d i c a t e d i n Table C - 1 . As would be expected, they are lower than the e q u i v a l e n t r e s u l t s i n Tab l e 7 which uses the o r i q i n a l demand f o r e c a s t . The c a s i c economic p r i n c i p l e o f r a t e s t r u c t u r e design i s t h a t marginal p r i c e should egual marginal economic c o s t f o r each 8 0 B . C . Hydro's management has been r e l u c t a n t t o r e l e a s e the s p e c i f i c s o f t h i s new demand f o r e c a s t . I have had t o assume t h a t each customer c l a s s maintains the same share of t o t a l demand as under the Task Force p r o j e c t i o n and t h a t the system l o a d f a c t o r assumption of 63.5 percent c o n t i n u e s t o be a p p r o p r i a t e . TABLE C-1 IMPACT ON B.C. HYDRO OF ALTERNATIVE RATE STRUCTURES NO RATE RATE STRUCTURE CHANGE STRUCTURE CHANGE : BASE CASE FULL M.C.P. (MP=MC with AP=AC)' (MP=MC f o r a l l U n i t s ) Growth Rate In Demand (%) (1976 - 1990) 8.1 Average Accounting Cost (1976 M i l l s per KWH) (1976 - 1990) 17.5 5.4 5.4 16.0 13.7 Gross Debt Outstanding In 1990 12.3 8.6 1.1 ( B i l l i o n s o f H i s t o r i c $) 131 customer c l a s s . T h i s g i v e s r i s e to the guestion of the a p p r o p r i a t e i n t r a - m a r g i n a l p r i c e . In the t e x t of t h i s paper, i n t r a - m a r g i n a l p r i c e s were assumed t o be a d j u s t e d so t h a t average p r i c e s were egual t o average accounting c o s t s f o r each c l a s s . Because of the p r o x i m i t y of the proposed marginal economic c o s t s and the e x i s t i n g average accounting c o s t s f o r the r e s i d e n t i a l and g e n e r a l c l a s s e s , a r e c o n c i l i a t i o n of the economic and accounting c r i t e r i a was not a n t i c i p a t e d to be d i f f i c u l t . A f l a t r a t e a t the new marginal economic c o s t , supplemented by a s m a l l s e r v i c e charge, would s a t i s f y both c r i t e r i a f o r the c l a s s e s as a whole. There would, of course, be a g e n e r a l s h i f t i n c o s t s from s m a l l e r e l e c t r i c i t y consumers to the l a r g e r ones w i t h i n each of these c l a s s e s . The d i f f i c u l t i e s i n implementing a new r a t e s t r u c t u r e would l i k e l y a r i s e with the f i f t y bulk customers. For t h i s c l a s s , the proposed marginal economic c o s t s were more than double the present accounting c o s t s . In the t e x t , a " v a l u a t i o n day" approach was suggested i n which the s u r p l u s e s f o r the c l a s s from f u l l marginal c o s t p r i c i n g would be r e t u r n e d to each customer on the b a s i s of h i s consumption on an i n i t i a l r e f e r e n c e date. T h i s i s perhaps the most economically "pure" way t o deal with the i s s u e , although i t may give r i s e t o c l a i m s of i n e q u i t y . I t i s , however, an approach used f r e q u e n t l y i n other matters, from income tax on c a p i t a l gains to compliance with a n t i - p o l l u t i o n standards. The Ontario Hydro study (1976c) has suggested t h a t the s u r p l u s e s from l a r g e users be returned on the b a s i s of the customer's consumption three years e a r l i e r . Regardless o f the method chosen to r e c o n c i l e the two c r i t e r i a , however, the c l a s s 132 as a whole w i l l be b e t t e r o f f s i n c e the higher marginal p r i c e s w i l l induce some to reduce t h e i r consumption, thereby slowing the u t i l i t y ' s growth and keeping average c o s t s below what they otherwise would have been. 8* An a l t e r n a t i v e approach would be to ignore the accounting and revenue c o n s t r a i n t s and apply the a p p r o p r i a t e marginal economic c o s t s f o r a l l u n i t s of consumption w i t h i n each c l a s s . T h i s would avoid some of the a d m i n i s t r a t i v e and implementation problems of the previous method, but c o u l d cause a l a r g e r impact on customers* b i l l s , p a r t i c u l a r l y i n the bulk c l a s s . Because marginal economic c o s t s exceed accounting c o s t s , the question of the s u r p l u s revenue that would r e s u l t must be addressed. At one extreme, the s u r p l u s p r o f i t s c o u l d be t r a n s f e r r e d to the p r o v i n c i a l government each year and put to a v a r i e t y o f uses. For example, a fund c o u l d be e s t a b l i s h e d t o f a c i l i t a t e c o n v e r s i o n by customers to e l e c t r i c i t y - c o n s e r v i n g t e c h n o l o g i e s , to a t t r a c t new i n d u s t r y or to provide r e d u c t i o n s i n income taxes. Any of these uses would be more economically e f f i c i e n t than the continued s u b s i d i z a t i o n of the marginal p r i c e o f e l e c t r i c i t y . Over 4 b i l l i o n h i s t o r i c d o l l a r s of a d d i t i o n a l p r o f i t s would be generated between 1981 and 1990 with a f u l l marginal c o s t p r i c i n g scheme (assuming median e l a s t i c i t i e s ) as compared with the case o f no r a t e s t r u c t u r e reform. At the other extreme, the new p r o f i t s c o u l d be r e t a i n e d by B.C. Hydro and used to f i n a n c e expansion and/or r e t i r e 8 1 T h i s i s analagous to the common property problem where the economic r e n t i s d i s s i p a t e d from r i s i n g average c o s t s because each i n d i v i d u a l does not f a c e the f u l l marginal c o s t s a s s o c i a t e d with h i s a c t i o n s . 133 outstanding debt, thereby r e d u c i n g the average c o s t of power t o B.C. Hydro yet f u r t h e r . The r e s u l t s of t h i s f u l l marginal c o s t p r i c i n g are a l s o shown i n T a b l e C-1, and are c o n t r a s t e d with those from the r a t e s t r u c t u r e suggested i n the t e x t of t h i s paper. In both c a s e s , the f u l l e f f e c t of the reform i s assumed to be f e l t by 1981 and the median e l a s t i c i t y estimates are used. Having examined the impact on B.C. Hydro of these v a r i o u s r a t e reform p o s s i b i l i t i e s , we t u r n now to review the e f f e c t s of these v a r i o u s proposals on the t o t a l revenues y i e l d e d by each o f the customer c l a s s e s . These r e s u l t s are contained i n Table C-2. The f i r s t column i n d i c a t e s the t o t a l revenue (in h i s t o r i c d o l l a r s ) to be d e r i v e d from each c l a s s between 1981 and 1990 with no r a t e s t r u c t u r e reform. The average p r i c e i n each c l a s s i s assumed t o be a d j u s t e d a n n u a l l y by a common percentage i n order t h a t B.C. Hydro's revenues egual i t s c o s t s (which i n c l u d e a d e s i r e d p r o f i t margin) . The next column shows the cumulative revenue (with the percentage change from column (1)) under the r a t e s e t t i n g procedures used i n the t e x t of t h i s paper. Marginal p r i c e s are set egual to marginal economic c o s t s while average p r i c e s are equated with average accounting c o s t s . Revenues f a l l both because of lower volumes and because of a r e d u c t i o n i n average u n i t accounting c o s t s . The t h i r d column shows the revenue e f f e c t i f the marginal economic c o s t s d e r i v e d i n the paper are a p p l i e d to a l l u n i t s of consumption i n each customer c l a s s , assuming the demand adjustment i n h e r e n t i n the median e l a s t i c i t y e s t i m a t e . T h i s i s i n c o n t r a s t to the f i n a l column's r e s u l t s which d e p i c t the TABLE C-2 IMPACT ON CUSTOMERS OF ALTERNATIVE RATE STRUCTURES CUMULATIVE REVENUE (Millions of Historic $) (1981 - 1990) CUSTOMER CLASS NO RATE STRUCTURE REFORM RATE STRUCTURE REFORM BASE CASE FULL M.C.P. FULL M.C.P. (MP=MC with AP=AC, (MP=MC for a l l Units, (MP=MC for a l l Units, Median E last ic i t ies ) Median E la s t i c i t i e s ) Zero E las t i c i t ies ) Residential 6456 4763 (-26.2%) 5687 (-11.9%) 6725 (+4.2%) General 7499 4923 (-34 5856 . (-21.9%) 7734 (+3.1%) Bulk 4145 1941 (-53.2%) ' 4430 (+6.9%) 8224 (+98.4%) 135 e f f e c t when there i s no demand adjustment to the f u l l marginal c o s t p r i c i n g . These f i g u r e s would r e p r e s e n t the impact i f no s u b s t i t u t i o n p o s s i b i l i t i e s became a t t r a c t i v e f o r any customer under the reformed r a t e s t r u c t u r e . The t o t a l c ost impact on each customer c l a s s would depend on the c o s t of the a l t e r n a t i v e s a v a i l a b l e t o i t s members. The f o u r t h column r e p r e s e n t s the most extreme c o s t impact, s i n c e i t assumes f u l l marginal c o s t p r i c i n g , no demand response, and no b e n e f i t s from the s u r p l u s revenues t o be generated by B.C. Hydro. The very s l i g h t r i s e i n e l e c t r i c i t y b i l l s f o r the r e s i d e n t i a l and gen e r a l c l a s s e s under t h i s extreme c o n d i t i o n i n d i c a t e s t h a t they would almost c e r t a i n l y b e n e f i t as a c l a s s under more r e a l i s t i c assumptions. And by a s s i s t i n g bulk users with conv e r s i o n s to e l e c t r i c i t y - c o n s e r v i n g equipment and/or with r e d u c t i o n s i n t h e i r c o s t s through grants or tax r e d u c t i o n s , they too c o u l d be made b e t t e r o f f under marginal c o s t p r i c i n g . T h i s appendix has presented some r a t h e r extreme p o s i t i o n s on how rate s t r u c t u r e reform c o u l d be accomplished. A r e a l i s t i c approach might combine these d i f f e r e n t methods. Average p r i c e s f o r each c l a s s c o u l d be s e t somewhere between the marginal economic and average accounting c o s t s . Some of the r e s u l t i n g s u r p l u s could be used to reduce B.C. Hydro's debt while the r e s t could be a p p l i e d t o reduce c o s t s f o r those c l a s s e s a d v e r s e l y a f f e c t e d by the r a t e reform. Other ways could a l s o be devised which t u r n i n t o r e a l i t y t he t h e o r e t i c a l improvement i n s o c i a l welfare p o s s i b l e from r a t e s t r u c t u r e s c o n s i s t e n t , with economic p r i n c i p l e s . 136 D. APPENDIX D D.I L i s t Of V a r i a b l e s . C o e f f i c i e n t s , And D e f i n i t i o n s D.1.1 Endogenous V a r i a b l e s A l l V a r i a b l e Names Ending With $76 Are Measured In M i l l i o n s Of 1976 $ A l l V a r i a b l e Names Ending With $H Are Measured In M i l l i o n s Of H i s t o r i c $ A l l V a r i a b l e Names Ending With $ Are Measured In M i l l i o n s Of Cu r r e n t $ A l l E l e c t r i c i t y U n i t s Are M i l l i o n s Of KWH Per Year Unless Otherwise Stated name d e s c r i p t i o n C1KWH$76 Net Cost Per KWH Generated C2KWH$76 Cost Per K«H Generated COPFIX$ F i x e d Operating Costs For Complete System C0PFIX1$ F i x e d Operating Costs To 230 KV L e v e l COPVAB$ V a r i a b l e Operating Costs COP$76 Annual Operating C o s t s Of P r o j e c t s COSTS$ T o t a l O p e r ating And C a p i t a l Costs DBULK Demand By Bulk C l a s s DEPACC$H Accumulated D e p r e c i a t i o n On New F a c i l i t i e s For School Tax Purposes DEPREC$ D e p r e c i a t i o n Charges DEXPOBT S a t i s f i e d Export Demand DGEN Demand By General C l a s s DGEOSS T o t a l Demand I n c l u d i n g Losses DGBOSSF Future T o t a l Gross Demand DIND Commercial And I n d u s t r i a l Demand DLGSS Losses On I n t e g r a t e d System DPEAK Maximum Annual One-hour Demand (MW) DPEAKF Future Peak Demand ORES R e s i d e n t i a l Demand DTOT T o t a l Demand Net Of Losses DTOTF Future T o t a l Net Demand DWKPL West Kootenay Power And L i g h t ' s Incremental Demand EIN REQ F i n a n c i a l Requirements Not I n t e r n a l l y Generated ($) FINREQB F i n a n c i a l Requirements To Be Met By Debt Financing{$) 1$ Investment IDIST$76 Investment In D i s t r i b u t i o n F a c i l i t i e s IGEN$76 Investment I n Generation P r o j e c t s ITRF$76 Investment In Transformation ITRS$76 Investment In Major Transmission And Sub-transmission P r o j e c t s ITRS1$76 Investment In Major A s s o c i a t e d Transmission P r o j e c t s INT$ T o t a l I n t e r e s t Charges INTOLDB$ Annual I n t e r e s t Payments Remaining On Bonds Issued P r i o r To 1976 KELEC Complete Stock Of E l e c t r i c i t y Supply C a p i t a l Approved A f t e r 1974 KELEC3 Stock Of E l e c t r i c i t y Supply C a p i t a l ($76) To Serve L a r q e s t Customers KELECU KPISC$H KPISDSH KPISG$H KPISH$H KPISTSH KPISTFSH KPISTS$H KPI S $76 KPISC$76 KPISD$76 KPISG$76 KPISH$76 KPISM$76 KPIST$76 KPST1J76 KPST3$76 KPVC1$76 KPVC3$76 KPVC4$76 KPVELEC1 KPVELEC2 KPVEIEC3 KPVELEC4 LNEW$H . LOLD$H aiss NOCUST PBDLK PBULK$76 PEXPOET PEXP$76 PGEN PGEN$76 PIND PIND$76 PKWHCST1 PRES PRES$76 PWCOST1 PWKPL PWKPL$76 RESMAR Stock Of E l e c t r i c i t y Supply C a p i t a l ($76) To Serve Smallest Customers Hew C o a l Generation P l a n t In S e r v i c e New D i s t r i b u t i o n P l a n t In S e r v i c e New Gas Turbines In S e r v i c e New Hydro P l a n t In S e r v i c e Transmission And Transformation P l a n t In S e r v i c e New Transformation P l a n t In S e r v i c e Major Tr a n s m i s s i o n And Sub-transmission P l a n t In S e r v i c e T o t a l New P l a n t In S e r v i c e Stock Of Post-74 C o a l - f i r e d P l a n t In S e r v i c e Stock Of Post-74 D i s t r i b u t i o n P l a n t In S e r v i c e Stock Of Post-74 Gas Turbine P l a n t In S e r v i c e Stock Of Post-74 H y d r o - e l e c t r i c P l a n t In S e r v i c e New Mi s c e l l a n e o u s P l a n t In S e r v i c e For 230 KV L e v e l Customers A l l New Transmission And Transformation P l a n t Stock Of New Major A s s o c i a t e d T r a n s m i s s i o n P r o j e c t s In S e r v i c e A l l New Transmission And Transformation P l a n t In S e r v i c e To Serve Customers At The 230 KV L e v e l Complete Discounted Cost For E l e c t r i c i t y S u p plied From P r o j e c t s Approved A f t e r 1974 Present Value Of Costs A s s o c i a t e d With Supplying L a r g e s t Customers Present Value Of Costs A s s o c i a t e d With Supplying Smallest Customers Present Value Of A c t u a l Energy Supplied (KWH) For P r o j e c t s Approved A f t e r 1974 Present Value Of A c t u a l Peak Power Supplied(MW) For P r o j e c t s Approved A f t e r 1974 Present Value Of A c t u a l Energy Produced (KWH) Present Value Of A c t u a l C a p a c i t y Produced (MW) Stock Of Post-75 New Bonds Outstanding Stock Of Debt Issued P r i o r To 1976 S t i l l Outstanding End Of Each P e r i o d F r a c t i o n Of Bevenue S u r p l u s / d e f i c i t Number Of E l e c t r i c i t y Customers (M) Average Bulk P r i c e ( $ ) Bulk P r i c e Export P r i c e ($) Export P r i c e General Price<$) General P r i c e C o m m e r c i a l / i n d u s t r i a l P r i c e ($) I n d u s t r i a l And Commercial P r i c e Average Average Average Average Average Average Average Complete Discounted Energy S u p p l i e d Average R e s i d e n t i a l Average R e s i d e n t i a l Complete Discounted Cost ($76) Per KWH A c t u a l P r i c e ($) P r i c e Cost ($76) Per Watt Of Peak Power S u p p l i e d Average West Kootenay Power And L i g h t P r i c e ( $ ) Average P r i c e To WKPL A c t u a l Reserve C a p a c i t y Margin 138 RES HARD Desired Reserve C a p a c i t y Margin SCAP A c t u a l C a p a c i t y C a p a b i l i t y (MS?) SCAPD Desired C a p a c i t y C a p a b i l i t y (MS) SCAPH Hydro Generation C a p a c i t y Capability(MW) SCAPSURP Su r p l u s ( d e f i c i t ) Of A c t u a l C a p a c i t y C a p a b i l i t y Over Desired C a p a c i t y Capability(MB) SENER T o t a l Energy Generated SENERB Ac t u a l Energy Produced At Burrard SENERBC Burrard's Energy C a p a b i l i t y SENERC Ac t u a l Energy Produced From Hat Creek C o a l SENERCAP T o t a l Energy C a p a b i l i t y SENERCC Hat Creek Coal C a p a b i l i t y SENERG A c t u a l Energy Produced From Gas Turbines SENERGC Gas Turb i n e s Energy C a p a b i l i t y SENERH A c t u a l Energy Produced From Hydro Sources SENERHC Hydro-generated Energy C a p a b i l i t y SENERK A c t u a l Energy Produced From East Kootenay C o a l SENERKC East Kootenay Coal Energy C a p a b i l i t y SENERM Ac t u a l Energy Imported From Other U t i l i t i e s SFPAYHTS Annual S i n k i n g Fund Payment And A d d i t i o n a l Funds Required For Bonds Maturing Before 1982 TGRANTS 'Grants'($) TLAND Land Taxes($) TLOCAL A l l L o c a l Taxes{$) TSCHOOL School Taxes ($) THATER Water L i c e n c e Costs{$) YBULK Revenue From Bulk Sales{$) YBU1KMCP Revenue From Bulk Sales Under F u l l M.C.P.{$) IEXPORT Revenue From Export S a l e s ($) YGEN Revenue From General S a l e s {$) YGENHCP Revenue From General Sales Under F u l l M.C.P.{$) YIHD Revenue From Commercial And I n d u s t r i a l Sales{$) YRES Revenue From R e s i d e n t i a l Sales{$) YRESMCP Revenue From R e s i d e n t i a l S a l e s Under F u l l M.C.P. ($) YSUEPMCP A d d i t i o n a l Net Income Under F u l l M.C.P. ($) YTOT T o t a l Revenues ($) YTOTMCP T o t a l Revenue From S a l e s Under F u l l M.C.P. ($) YTOTSUBP T o t a l B.C. Hydro Net Income under F u l l M.C.P. ($) YWKPL Revenue From WKPL Sales{$) 139 0.1.2 Exogenous V a r i a b l e s A l l V a r i a b l e Names Ending With $76 Are Measured In M i l l i o n s Of 1976 $ A l l v a r i a b l e Names Ending With $H Are Measured In M i l l i o n s Of H i s t o r i c $ A l l V a r i a b l e Names Ending With $ Are Measured I n M i l l i o n s Of C u r r e n t $ A l l E l e c t r i c i t y U n i t s Are M i l l i o n s Of KWH Per Year Unless Otherwise S t a t e d name d e s c r i p t i o n BULKRED Bulk C l a s s Demand Change COVERAGE I n t e r e s t Coverage P o l i c y C o e f f i c i e n t DBULK Demand By Bulk C l a s s DBULKF Future Demand By Bulk C l a s s DGEN Demand By General C l a s s DGENF Future Demand By General C l a s s DGBOSSF Future T o t a l Gross Demand DIND Commercial And I n d u s t r i a l Demand DLOSS Losses On I n t e g r a t e d System DPEAKF Future Peak Demand <MW) ORES R e s i d e n t i a l Demand DRESF Future Demand By R e s i d e n t i a l C l a s s DTOTF Future T o t a l Net Demand DWKPL West Kootenay Power And L i g h t ' s Incremental Demand DWKPLF Future Demand By WKPL. GENRED General C l a s s Demand Change IDC$ I n t e r e s t During C o n s t r u c t i o n IDCG1$...IDCG50$ I n t e r e s t During C o n s t r u c t i o n For Generation P r o j e c t IDST1$76 IDST2$76 IGEN$ IGEN$76 IMISC$76 INTRED$H I n t e r e s t During C o n s t r u c t i o n For As s o c i a t e d Major T r a n s m i s s i o n P r o j e c t Annual Each IDCT1$...IDCT45$ Annual Each Investment In D i s t r i b u t i o n Investment In D i s t r i b u t i o n E x i s t i n g Customers IG1$...IG50$ On In In In In F a c i l i t i e s For F a c i l i t i e s For New Customers Growth By IT1$...I Investment Investment Investment Investment Reductions Of Bonds T45$ Investment Each Generation P r o j e c t Generation P r o j e c t s Generation P r o j e c t s Other E l e c t r i c P l a n t I n t e r e s t Charges Due To Maturing Issued Before 1976 ITRF1$76 ITRF2$76 ITRS1$ ITRS1$76 ITRS2$76 ITRS3$76 KPISC$H KPISC$76 KPISG$H On Each Major A s s s o c i a t e d Transmission P r o j e c t Investment In Transmission Transformation In Sub-transmission Transformation In Major A s s o c i a t e d Transmission P r o j e c t s In Major A s s o c i a t e d T r a n s m i s s i o n P r o j e c t s In Non-associated Major Transmission P r o j e c t s In Sub-transmission L i n e s Generation P l a n t In S e r v i c e Post-74 Hat Creek P l a n t In S e r v i c e Investment Investment Investment Investment Investment New Co a l Stock Of New Gas Tu r b i n e s In S e r v i c e KPISGS76 Stock Of Post-74 Gas Turbine F a c i l i t i e s In S e r v i c e KPISB$H New Hydro P l a n t In S e r v i c e KPISH$76 Stock Of Post-74 H y d r o - e l e c t r i c Plant In S e r v i c e KPISK$76 Stock Of Post-74 East Kootenay C o a l - f i r e d P l a n t In S e r v i c e KPIST$76 a l l New Transmission and Transformation P l a n t KPIST 1$H New Major Transmission P l a n t In S e r v i c e KPIST2$H New Non-associated Major Transmission and Subtrans- Mis s i o n P l a n t In S e r v i c e KPSTF$76 New Transformation P l a n t In S e r v i c e KPST1$76 New Major T r a n s m i s s i o n Plant In S e r v i c e KPST2$76 New Non-associated Transmission and Sub-transmission P l a n t In S e r v i c e KPST3S76 A l l New Transmission And Transformation P l a n t In S e r v i c e To Serve Customers At The 230 KV L e v e l KPST4$76 Stock Of New Sub-transmission Transformation P l a n t In S e r v i c e LMWOSF$ S h o r t f a l l In S i n k i n g Fund For Bonds Maturing A f t e r 198 L0LDM$H Stock Of Debt Issued P r i o r To 1976 That Matures Each Year NOC0ST Number Of E l e c t r i c i t y Customers (M) PEXOG P r i c e L e v e l s QSTART Switch I n d i c a t i n g Energy Production By P r o j e c t s RESMARDF Future D e s i r e d Reserve Margin fiESRED R e s i d e n t i a l C l a s s Demand Change SCAPB Ca p a c i t y C a p a b i l i t y Of Burrard P l a n t (MW) SCAPC Capacity C a p a b i l i t y Of Hat Creek P l a n t s (MR) SCAPDF D e s i r e d Future C a p a c i t y Capability(MW) SCAPF Future C a p a c i t y Capability(MW) SCAPG C a p a c i t y C a p a b i l i t y Of Gas Turbine P l a n t s (MW) SCAPH Ca p a c i t y C a p a b i l i t y Of H y d r o - e l e c t r i c P l a n t s (MW) SCAPK Ca p a c i t y C a p a b i l i t y Of East Kootenay P l a n t s (MW) SEC NEW New Energy C a p a b i l i t y SENCAC1 Hat Creek's C a p a b i l i t y At Year End SENCAPF Future Expected Energy C a p a b i l i t y SENERBAC Burrard's Energy C a p a b i l i t y SENERCAC Average Hat Creek C o a l C a p a b i l i t y Throughout Year SEN ERGAC Average Gas Turbines Energy C a p a b i l i t y Throughout Year SENERHAC Average Energy C a p a c i t y Throughout Year From Hydro sources During Average R a i n f a l l P e r i o d s SENERHCC Average Energy C a p a c i t y Throughout Year From Hydro Sources During C r i t i c a l R a i n f a l l P e r i o d s SENERKAC Average East Kootenay C o a l Energy C a p a c i t y Throughout Year SENGAC1 Gas Turbines Energy C a p a b i l i t y At Year End SENHAC1 Energy Generation Capacity From H y d r o - e l e c t r i c Sources During Average R a i n f a l l P e r i o d At Year End SENHCC1 Energy Generation C a p a c i t y From H y d r o - e l e c t r i c Sources During C r i t i c a l R a i n f a l l Period At End Of Ea< Year SENKAC1 Energy Generation C a p a c i t y From East Kootenay C o a l At Year End STARG1...STARG50 Approval Dates For Each Generation P r o j e c t 141 START 1. . START45 Approval Dates For Each A s s o c i a t e d Major Transmission P r o j e c t STPNOM Nominal Rate Of S o c i a l Time P r e f e r e n c e TOTSED T o t a l Demand Change Due To P r i c e Change 142 D.I.3 C o e f f i c i e n t s Values Shown Are Those In The Base Case no. value d e s c r i p t i o n 1849 63.5 Annual Load Factor (converts MM KWH To MW) 1850 0.057 Switch - I n d i c a t e s D e p r e c i a t i o n Used For Economic A n a l y s i s 1851 1.2 I n t e r e s t During C o n s t r u c t i o n For Transmission P r o j e c t s 1852 1. 1 I n t e r e s t During C o n s t r u c t i o n For Transformation P r o j e c t s 1853 .0049 Annual F i x e d Operating Cost C o e f f i c i e n t For Hydro F a c i l i t i e s 1854 .024 Annual Fixed Operating Cost C o e f f i c i e n t For Coal F a c i l i t i e s 1855 .0108 Annual F i x e d Operating Cost C o e f f i c i e n t For Gas F a c i l i t i e s 1856 .0095 Annual Fixed Operating Cost C o e f f i c i e n t For Transmission And T r a n s f o r m a t i o n F a c i l i t i e s 1857 .033 Annual Fixed Operating Cost C o e f f i c i e n t For D i s t r i b u t i o n F a c i l i t i e s 1858 .015 Average M i l l Hate In 1976 1859 .01 Rate Used In Determining Annual * grants* 1860 .0005 Water L i c e n c e Charge ($MM/MW) 1861 .00025 Water L i c e n c e Charge ($/KWH) 1862 .0055 Annual V a r i a b l e Operating Cost C o e f f i c i e n t For Hat Creek Coal Generation 1863 .0059 Annual V a r i a b l e Operating Cost C o e f f i c i e n t For East Kootenay Coal Generation 1864 .0187 Annual V a r i a b l e Operating Cost C o e f f i c i e n t For Burrard Generation | g a s - o i l P r i c e P a r i t y ) 1865 .03 Annual V a r i a b l e Operating Cost C o e f f i c i e n t For Gas Turbines 1866 0.0 Demand Shock 186 7 .88 Int e g r a t e d E l e c t r i c P l a n t In S e r v i c e : t o t a l B.C. Hydro P l a n t In S e r v i c e 1868 .94 Net Out I n t e r e s t Earned From S i n k i n g Fund Investments 1869 227.69 Gross I n t e r e s t On Debt For B.C. Hydro In 1975 1870 .01 Percent Of Outstanding Pre-1976 Debt C o n t r i b u t e d Annually To S i n k i n g Fund 1871 .0175 Percent Of Outstanding Post-1975 Debt C o n t r i b u t e d Annually To S i n k i n g Fund 1872 . 1 Annual Nominal I n t e r e s t Rate For B.C. Hydro Post-1975 Debt 1873 .5 P r o p o r t i o n Of E l e c t r i c i t y B..C. Hydro Seeks To Export A c t u a l l y Purchased 1874 .0143 Inverse Of Expected S e r v i c e L i f e Of Hydro F a c i l i t i e s 1875 .0286 Inverse Of Expected S e r v i c e L i f e Of Co a l And Gas Turbine F a c i l i t i e s 1876 .0222 Inverse Of Expected S e r v i c e L i f e Of Transmission F a c i l i t i e s 1877 .0272 Inverse Of Expected S e r v i c e L i f e Of D i s t r i b u t i o n F a c i l i t i e s 1878 .02 Average Import P r i c e Of E l e c t r i c i t y 1879 .0095 Export P r i c e Of E l e c t r i c i t y 1880 1.25 Real C a p i t a l Cost Adjustment For New Generation 143 F a c i l i t i e s 1881 1.0225 Real Annual Sage Rate Adjustment 1882 1.02 Real Annual C o a l Value Adjustment 1883 1.02 Real Annual G a s / o i l Value Adjustment 1885 63.5 Annual Load F a c t o r For Demand Shock 1886 Gross Demand Shock - Set In Model 1887 76. I n i t i a l Year Of Demand Shock 1888 0.0 Demand Shock In 1976 Only 1889 0.0 Shock I n Number Of Customers 1890 .075 P r i v a t e A f t e r - t a x Real Cost Of Funds 1891 0.0 Inverse Of S e r v i c e L i f e Used - Set In Model 1894 .075 Real Rate Of S o c i a l Time Preference 1895 .03 C o r p o r a t i o n Tax In Other Industry 1900 0.0 Set In Model - Supply Approval Date Shock 1901 1.39 Adjustment From $74 Estimate To $76 I n c l u d i n g 1902 1.39 Corporate Overhead For Each Group Of Major Generation 1903 1.39 And Transmission P r o j e c t s 1904 1. 39 Continued 1905 1. 39 1906 1.39 1907 1. 39 1908 1. 39 1909 1.53 1910 1.53 191 1 1.53 1912 1. 47 1913 1.39 1914 1. 47 1915 1.47 1916 1.39 1917 1.39 1918 1.53 1919 1..53 1920 1.47 1921 1.47 1922 1.47 1923 1.47 1931 1.39 1932 1.39 1933 1.39 1934 1.39 1935 1.39 1936 1.47 1937 1.47 1938 1.47 1939 1.47 1940 1. 47 1941 1.47 1942 1.47 1943 1. 47 1944 1. 47 1945 1. 47 1951 1.39 1952 1.39 1953 1.39 1954 1. 39 144 1956 1.39 1958 1.39 1959 1.39 1960 1.39 197 1 1.39 1972 0.0 Real Rate Of I n f l a t i o n - Set In Model 1981 1.39 C o n t i n u a t i o n Of C a p i t a l Cost Adjustment F a c t o r s For Each 1986 1.39 Group Of Major Generation And Tr a n s m i s s i o n P r o j e c t s 1988 1. 39 1990 1.39 1994 1.39 1995 1.39 2000 .062 Investment In Non-associated Major Transmission ($MM/MW) 2001 .026 Investment In Sub-transmission L i n e s ($MM/MW) 2002 .012 Investment In Tra n s m i s s i o n Transformation ($MM/MW) 200 3 .0 36 Investment In Sub-transmission Transformation <$MM/MH) 200 4 1.25 Investment In D i s t r i b u t i o n Per New Customer($MM/M Cust) 2005 .019 Investment In D i s t r i b u t i o n Per Current Cust. ($MM/MW) 2006 .017 Investment In Other E l e c t r i c P l a n t ($MM/MK»H) 2007 0.0 S w i t c h - i n d i c a t e s C r i t i c a l Rain Period I f Not Zero 2010 0.0 Switch- I n d i c a t e s U n i t For Mar g i n a l Cost A n a l y s i s 2011 0.0 S w i t c h - i n d i c a t e s P r o j e c t For Marginal Cost A n a l y s i s 2012 0.0 S w i t c h - i n d i c a t e s Use Of Demand Changes From P r i c e E f f e c t s 2013 17.0 Old Marginal P r i c e For R e s i d e n t i a l C l a s s 2014 26.0 New Marginal P r i c e For R e s i d e n t i a l C l a s s 2015 15.0 Old Average Marginal P r i c e For General C l a s s 2016 24.0 New Marginal P r i c e For General C l a s s 2017 10.0 Old Combined M a r g i n a l P r i c e For Bulk C l a s s 2018 22.0 New Combined Marginal P r i c e For Bulk C l a s s 2019 0.4 Absolute Value-own P r i c e E l a s t i c i t y - r e s i d e n t i a l C l a s s 2020 0.6 Absolute Value-own P r i c e E l a s t i c i t y - g e n e r a l C l a s s 2021 0.8 Absolute Value-own P r i c e E l a s t i c i t y - b u l k C l a s s 2022 V a r i e s B a s i c Net Demand Readjustment C o e f f i c i e n t 2023 Set In Model - Present Net Demand Readjustment C o e f f i c i e n t 2024 Set In Model - Future Net Demand Readjustment C o e f f i c i e n t 2025 0.0 S w i t c h - i n d i c a t e s A d d i t i o n a l P r o j e c t Approval Dates To Follow 145 D.1.4 Generation and Transmission P r o j e c t s no. d e s c r i p t i o n 1 Kootenay Canal(1-2) 2 Kootenay Canal (3-4) 3 Mica (1-2) 4 Mica{3) 5 Mica (4) 6 S i t e One (1-3) 7 S i t e One (4) 3 Seven M i l e (1-3) 9 Revelstoke (1-2) 10 Revelstoke(3) 11 Revelstoke(4) 12 Kootenay D i v e r s i o n 13 Shrum(10) 14 McGregor D i v e r s i o n (without S i t e C) 15 McGregor D i v e r s i o n (with S i t e C) 16 Mica (5) 17 Mica{6) 18 Revelstoke(5) 19 Revelstoke(6) 20 Seven Mile(4) 21 S i t e C{1-2) 22 S i t e C{3) 23 S i t e C{4) 31 Vancouver I s l a n d Gas Turbines(1) 32 Vancouver I s l a n d Gas Turbines(2) 33 E x t r a Gas Turbines(150 MH) 34 E x t r a Gas Turbines(300 MB) 35 Ext r a Gas Turbines(600 MB) 36 Hat Creek(1) 37 Hat Creek{2) 38 Hat Creek(3) 39 Hat Creek(4) 40 Hat Creek(5) 41 Hat Creek(6) 42 Hat Creek(7) 43 Hat Creek(8) 44 East Kootenay(1) 45 East Kootenay(2) D.2 OUTLINE OF B.C. HYDRO MODEL 146 SOME CONVENTIONS: * DENOTES MULTIPLICATION X**2 DENOTES 'X SQUARED' J1L* DENOTES A ONE-YEAR LAG OPERATION NTIME IS THE CALENDAR YEAR, WITH 75 REPRESENTING 1975, 76 REPRESENTING 1976, AND SO ON. >= DENOTES 'GREATER THAN OS EQUAL TO' <= DENOTES * LESS THAN OR EQUAL TO» K7 DENOTES THE CURRENT SIMULATION YEAR M9 DENOTES THE TOTAL NUMBER OF SIMULATION YEARS IF K7=M9 IS READ 'IF THE SIMULATION IS IN ITS TERMINAL YEAR' SUBROUTINE POLD1 DETERMINE INTEGRATED ELECTRICITY REQUIREMENTS BASED ON B C HYDRO'S MAY 1975 PLANNING FORECAST A(2023) - CURRENT NET DEMAND ADJUSTMENT COEFFICIENT IF NTIME>=76 AND NTIME<=90 THEN A(2023)= 1.- ((RTIME-75.) * (1.-A(2022) )/15.) IF NTIME<76 THEN A(2023)=1. IF NTIME>90 THEN A(2023)=A(2022) A (2024) - FUTURE NET DEMAND ADJUSTMENT COEFFICIENT IF NTIME>=75 AND NTIME<=84 THEN A(2024)= 1.-( (RTIME-69.) * (1.-A (20 22))/1 5.) IF NTIME>=85 THEN A(2024)=A (2022) DBES - RESIDENTIAL DEMAND IF NTIME= 75 THEN DRES= 5600. * A (2023) IF NTIME= 76 THEN DRES= 6100. *A(2023) IF NTIME= 77 THEN DRES= 6700. *A (2023) IF NTIME= 78 THEN DRES= 7500. * A (2023) IF NTIME= 79 THEN DRES= 8400. * A (2023) IF NTIM E= 80 THEN DRES= 9200. A(2023) IF NTIME= 81 THEN DRES= 10000 « *A (2023) IF NTIME= 82 THEN DRES= 11000 *A (2023) IF NTIME= 83 THEN DRES= 12000 *A (2023) IF NTIME= 84 THEN DRES= 13100 • *A (2023) IF NTIME= 85 THEN DRES= 14500 * *A(2023) IF NTIME= 86 THEN DRES= 15800 • *A (2023) IF NTIME= 87 THEN DRES= 17000 • *A (2023) IF NTIME= 88 THEN DRES= 18300 *A (2023) IF NTIME= 89 THEN DRES= 19700 • *A (2023) IF NTIME>=90 THEN DRES=21000.*A(2023) DGEN IF IF IF IF IF IF IF IF I F IF IF IF IF IF IF IF DBOLK IF IF IF IF IF IF I F IF IF IF IF IF IF IF IF IF - GENERAL NTIME=75 NTIME=76 NTIME=77 NTIME=78 NTIME=79 NTIME=80 NTIME=81 NTIME=82 NTIME=83 NT.IME=84 NTIME=85 NTIME=86 NTIME=87 NTIME=88 NTIME=89 NTIME>=90 CLASS DEMAND THEN DGEN=7000. THEN DGEN=8100. THEN DGEN=900O. THEN DGEN=10OO0 THEN DGEN=11100 THEN DGEN=122G0 THEN DGEN=13300 THEN DGEN=14400 THEN DGEN=15500 THEN DGEN=16700 THEN DGEN=18000 THEN DGEN=19500 THEN DGEN=21000 THEN DGEN=22500 THEN DGEN=24Q00 THEN DGEN=2550 147 *A(2023) *A (2023) *A{2023) .*A{2023) . *A{2023) .*A (2023) .*A (2023) .*A (2023) .*A{2023) .*A (2 023) .*A (2023) .*A (2023) . *A (2 023) .*A (2023) .*A (2023) 0.*A(2023) - BULK CLASS NTIME=75 THEN NTIME=76 THEN NTIME=77 THEN NTIME=78 THEN NTIME=79 THEN NTIME=80 THEN NTIME=81 THEN NTIME=82 THEN NTIME=83 THEN NTIME=84 THEN NTIME=85 THEN NTIME=86 THEN NTIME=87 THEN NTIHE=88 THEN NTIME=89 THEN NTIME>=90 THE DEMAND DBULK= DBULK= DBULK= DBULK= DBULK= DBULK= DBULK= DBULK= DBULK= DBULK= DBULK= DBULK= DBULK= DBULK= DBULK= N DBUXK 7200. 8400. 9500. 10500 11600 12800 14200 15600 17300 18900 20400 22200 24400 26600 28900 = 3150 *A (2023) *A(2023) *A (2 023) .*A{2023) •*A(2023) .*A{2023) .*A{2023) .*A(2023) .*A{2023) . *A(2023) .*A(2023) . *A{2023) .*A{2023) . *A{2023) .*A{2023) 0.*A (2023) DIND - COMMERCIAL DIND=DGEN*DBUI»K AND INDUSTRIAL DEMAND DWKPL - WEST KOOTE IF NTIME=75 THEN IF NTIME=76 THEN IF NTIME=77 THEN IF NTIME=78 THEN IF NTIME=79 THEN IF NTIME=80 THEN IF NTIME=81 THEN IF NTIME=82 THEN IF NTIME=83 THEN IF NTIME=84 THEN IF NTIME=85 THEN IF NTIME=86 THEN IF NTIME=87 THEN IF NTIME=88 THEN IF NTIME=89 THEN IF NTIME>=90 THE NAY POWER AND LIGHT'S INCREMENTAL DEMAND DWKPL=0. D1KPL=0. DWKPL=200.*A(2023) DWKPL=400.*A(20 23) DWKPL=700.*A(2023) DWKPL=1000.*A(2023) DWKPL= 1300. *A (2023) DWKPL=1700.*A(2023) DWKPL=2100.*A{2023) DWKPL=2500. *A(2023) DWKPL=2800.*A (2023) DWKPL=3000.*A (2023) DWKPL=3300.*A{202 3) DWKPL=3600. *A (2023) DWKPL=3800. *A{2023) N D«KPL=4100.*A{20 23) NOCUST - NUMBER OF ELECTRICITY CUSTOMERS IF NTIME=75 THEN NOCUST=859. IF NTIME=76 THEN NOCUST=898. IF NTIME= 77 THEN NQC0ST= 939. IF NTIME= 78 THEN NOCOST= 982. IF NTIME= 79 THEN NOCUST= 1027. IF NTIME= 80 THEN NOCUST= 1074. IF NTIME= CO THEN NOC0ST= 1123. IF NTIME= 82 THEN NOCOST= 1175. IF NTIME= 83 THEN NOCGST= 1229. IF NTIME= 84 THEN NOCUST= 1285. IF NTIH E= 85 THEN NOCUST= 1343. IF NTIME= 86 THEN NOCOST= 1405. IF NTIME= 87 THEN NOCUST= 1469. IF NTIME= 88 THEN NOCOST= 1536. IF NTIME= 89 THEN NOC0ST= 1607. IF HTIHE> =90 THEN NOC0ST =1680. DRESF - EXPECTED RESIDENTIAL DEMAND SIX YEARS HENCE IF NTIME=75 THEN DRESF=10000.*A(2024) IF NTIME=76 THEN DRESF=11000.*A (2024) IF NTIME=77 THEN DRESF=12000.*A(2024) IF NTIME=78 THEN DRESF=13100.*A(2024) IF NTIME=79 THEN DRESF=14500.*A(2024) IF NTIME=80 THEN DRESF=15800.*A (2024) IF NTIME=81 THEN DRESF=17000.*A(2024) IF NTIME=82 THEN DRESF=18300.*A(2024) IF NTIME=83 THEN DRESF=19700-*A (2024) IF NTIME>=84 THEN DRESF=21000. *A (2024) DGENF - EXPECTED GENERAL DEMAND SIX YEARS HENCE IF NTIME=75 THEN DGENF=13300.*A(2024) IF NTIME=76 THEN DGENF=14400.*A (2024) IF NTIHE=77 THEN DGENF=15500.*A(2024) IF NTIME=78 THEN DGENF=16700.*A(2024) IF NTIME=79 THEN DGENF=18000.*A (2024) IF NTIME=80 THEN DGENF=19500.*A(2024) IF NTIME=81 THEN DGENF=2 1000.'"A (2024) IF NTIME=82 THEN DGENF=22500.*A(2024) IF NTIME=83 THEN DGENF=24000.*A(2024) IF NTIME>=84 THEN DGENF=25500.*A (2024) DBULKF - EXPECTED BULK DEMAND SIX YEARS HENCE IF NTIME=75 THEN DBULKF=14200.*& (2024) IF NTIHE=76 THEN DBOLKF= 15600.*A (2024) IF NTIME=77 THEN DBULKF=17300.*A(2024) IF NTIME=78 THEN DBDLKF= 18900. *A (2 024) IF NT.IME=79 THEN DBULKF= 20400. *A (2024) IF NTIME=80 THEN DBULKF=22200.*A (2024) IF NTIME=81 THEN DB0LKF=24400.*A (2024) IF NTIME=82 THEN DBULKF=26600.*A (2024) IF NTIME=83 THEN DBOLKF=28900.*A (2024) IF NTIME>=84 THEN DBOLKF=31500.*A(2024) DHKPL - EXPECTED HKPL DEMAND SIX YEARS HENCE IF NTIME=75 THEN DHKPLF=1300.*A(2024) IF NTIME=76 THEN DWKPLF=1700.*A(2024) I F NTIME=77 THEN DwKPLF=2100.*A(2024) IF NTIME=78 THEN DWKPLF=2500.*A(2024) IF NTIME=79 THEN DWKPLF=2800.*A(2024) IF NTIME=80 THEN DWKPLF=3000.*A(2024) IF NTIME=81 THEN DWKPLF=3300.*A(2024) IF NTIME=82 THEN DHKPLF=3600.*A(2024) IF NTT 13E= 83 THEN DHKPLF=3800.*A{2024) IF NTIME>=84 THEN DWKPLF=4100. *A (2 024) 149 SUBROUTINE POLS 1 SENERBC - BURRARD *S ENERGY CAPABILITY SENEHBAC=5520. SET APPROVAL DATE FOR MAJOR GENERATION AND TRANSMISSION PROJECTS STARG1=75. STARG2=76. STARG3=75. STARG4=77. STARG5=78. STARG6-=75. STARG7=76. STARG8=75. START1=75. START2=76. START3=75. START4=77. START6=75. START8=75. IF A (2025) NOT= 1. THEN GO TO 5 HERE TO SET APPROVAL DATES FOR REVELSTOKE AND HAT CREEK I STARG9=76. STARG10=78. STARG11=79. STARG36=78. STARG37=81. STARG38=81. , STARG39=83. START9=76. , START10=78. START36=78. START38=81. 5 IF NTIWE>75 THEN GO TO 10 INCORPORATE REAL CAPITAL COST ADJUSTMENT 1906) =A1 (1906) *A (1880) A 1907) =A ;1907) *A ;1880) A 1908) =A (1908) *A (1880) A I 1909) =A [1909) *A (1880) A (1910) = A [1910) *A (1880) A | [ 1911) =A i 1911) *A ;1880) A [1912) =A (1912) *A [1880) A | [1913) =k{ ; 1913) * A (1880) A (1914) = A [1914) *A (1880) A [ 1915] =A ;1915) *A( 11880) A 1916] = A [1916) *A ;1880) A I ,1917) =A 1917) *A \ [1880) A (1918) = A (1918) *A [1880) A I '1919) =A i 1919) *A ;1880) A I 1920) = &• (1920) *A (1880) A (1921) =A (1921) *A (1880) A [1922) =A (1922) *A, (1880) A| [1923) = A (1923) *A (1880) [1931) =A (1931) *A (1880) A 1932) = A (1932) *A (1880) a i [1936) =A [1936) *A [1880) A j [1937) = A [1937) *A [1880) A( 1938) =A ;1938) *A (1880) A j [1939) = A ;1939) *a (1880) A 1 ' 1940) =A ;1940) *A< (1880) A 1941) = 8 [1941) *A (1880) Ai J942) = A ;1942) *A< (1880) A 1943) = A [1943) *A (1880) Al [ 1944) =A 1944) *A (1880) A [1945) =A [1945) *A (1880) REAL COST ADJUSTMENTS ($76) HYDRO - ANNUAL FIXED COSTS DUE TO HAGE INCREASES 10 A(1853) =.003+{(A(1853)-.003) *A (1881) ) COAL - ANNUAL FIXED COSTS (IAGE INCREASES) A (1854) =.006* ({A (1854)-.006) *A (1881)) GAS TURBINE - ANNUAL FIXED COSTS (WAGE INCREASES) A (1855) =.0045+{ (A{1855) -.0045) *A{1881) ) TRANSMISSION AND TRANSFORMATION - ANNUAL FIXED COSTS (HAGE INCREASES) A(1856)=.003+((A(1856) - .003) *A{1881) ) DISTRIBUTION - ANNUAL FIXED COSTS (HAGE INCREASES) A (1857) =.002+ ({A (1857) -.002) *A (1881) ) COAL - ANNUAL VARIABLE COSTS DUE TO ENERGY VALUE INCREASES A (1862) =A (1862) *A(1882) A{ 1863) =A (1863) *A(18 82) GAS/OIL - ANNUAL VARIABLE COSTS (ENERGY INCREASES) A( 1864)=A{1864) *A(1883) A(1865)=A{1865) *A (1883) SUBROUTINE DEMAND DEMAND EQUATIONS DRES - RESIDENTIAL DEMAND, PRICE ADJUSTED IF A(2012) NOT= 1. THEN GO TO 2 IF NTIME<77 THEN GO TO 2 I F NTIME=77 THEN DRES= (1.-.2* (1.-RESRED) ) *DRES IF NTIME=78 THEN DRES= 151 (1. -. 4* (1.-RESRED) ) *DRES IF NTIME=79 THEN DRES= (1.-. 6* ( 1.-RESREB) ) *DRES IF NTIME=80 THEN DRES= (1.-. 8* (1.-RESRED) ) *DRES IF NTIME>=81 THEN DRES= (1.-1.*(1.-RESRID) ) *DRES GO TO 3 2 DRES=DRES 3 IF RTIME=76. THEN DRES= DRES•A(1888) DGEN - GENERAL CLASS DEMAND, PRICE ADJUSTED IF A(2012) NOT= 1. THEN GO TO 4 IF NTIME<77 THEN GO TO 4 IF NTIME=77 THEN DGEN= (1.-. 2* (1 ,-GENRED)) *DGEN IF NTIME=78 THEN DGEN= (1.-.4* (1.-GENRED))*DGEN IF NTIME=79 THEN DGEN= (1.-.6*(1.-GENRED))*DGEN IF NTIME=80 THEN DGEN= (1.-.8* (1.-GENRED) ) *DGEN IF NTIME>=81 THEN DGEN= (1.-1.* (1.-GENRED) ) *DGEN GO TO 5 4 DGEN=DGEN DBULK - BULK DEMAND, PRICE ADJUSTED 5 IF A(2012) NOT= 1. THEN GO TO 6 IF NTIME<77 THEN GO TO 6 IF NTIME=77 THEN CBULK= (1.-.2*(1.-BULKRED))*DBULK IF NTIME=78 THEN DBULK= (1.-.4* (1,-BULKRED))*DBULK I F NTIME=79 THEN DBULK= (1.-.6*(1. —BULKRED) ) *DBULK IF NTIME=80 THEN DBULK= (1.-.8* ( 1.-BULKRED))*DBULK IF NTIME>=81 THEN DBULK= (1.-1.* (1.-BULKRED) ) *DBULK GO TO 7 6 DBULK=DBULK DIND - COMMERCIAL AND IND 0 S TBI AL DEMAND 152 7 DIND=DGEN + DBULK HEBE IP DEMAND SHOCK INTBODOCED IF RTIME>=A{1887) THEN DIND=DIND+A (1866) DWKPL - WEST KOOTENAY POWER AND LIGHT'S INCBEMENTAL DEMAND DffKPL=DWKPL NOCDST - NDMBEB OF ELECTRICITY CUSTOMERS IF BTIME<76. THEN NOCUST=NOCUST IF BTIME>=76. THEN NOCUST=NOCUST*A (1 889) DTOT - TOTAL DEMAND NET OF LOSSES DTOT=DRES*DIND+DWKPL DLOSS - LOSSES ON INTEGRATED SYSTEM DLOSS=.2527+.1107*DTOT DGBOSS - TOTAL DEMAND INCLUDING LOSSES DGBGSS=DTOT + DLOS S A(18 86) - SET GROSS DEMAND SHOCK A(1886)=1. 1107*A(1866) DPEAK - MAXIMUM ONE-HOUR DEMAND IF A (1885) =0. THEN GO TO 10 IF RTIME<A(1887) THEN DPEAK=DGROSS/|A(1849)*.0876) IF BTIME>=A(1887) THEN BPEAK= (DGROSS-A (1 886) ) / (A (1849) *.0876) +A(1886)/(A (1885) *.0876) GO TO 20 HERE I F DEMAND SHOCK HAS NO EFFECT ON PEAK DEMAND 10 IF BTIME<A(1887) THEN DPEAK=DGROSS/(A(1849)*.0876) IF RTIME>=A(1887) THEN DPEAK=(DGROSS-A(1886))/ (A (1849) *.0876) PEXOG - FUTURE PRICE LEVELS IF NTIME=75 THEN PEXOG=1.83 IF NTIME=75 THEN J1L*PEXOG=1.67 IF NTIME=75 THEN J2L*PEXOG=1.5 IF NTIME=75 THEN J3L*PEXOG=1.4 IF NTIME=76 THEN PEXOG=2.11 IF NTIME=76 THEN J2L*PEXOG=1.67 IF NTIME=76 THEN J3L*PEXOG=1.5 IF NTIME=77 THEN PEXOG=2.32 IF NTIME=77 THEN J3L*PEXOG=1.67 IF NTIME=78 THEN PEXOG=2.55 I F NTIME=79 THEN PEXOG=2.81 IF NTIME=80 THEN PEXOG=3.09 IF NTIME>=81 THEN PEXOG=1.05*J1L*PEX0G 153 A (1972) - SET EAT E OF INFLATION A(1972) =(PEXOG/J1L*PEXOG)-1. INTRED$H - REDUCTIONS IN INTEREST CHARGES DUE TO MATURING OF BONDS ISSUED BEFORE 1976 IF NTIME=75 THEN INT8ED$H= 0. IF NTIME=76 THEN INTRED$H= .97 IF NTIME=77 THEN INTRED$H= 2. 61 IF NTIME=78 THEN INTREDSH= 0. IF NTIME=79 THEN INTRED$H= -72 IF NTIME=80 THEN INTRED$H= 5. 22 IF NTIME=81 THEN INTBED$H= 5. 64 IF NTIME=82 THEN INTRED$H= 15 .16 IF NTIME=83 THEN INTRED $H= 0. IF NTIME=84 THEN INT RED$B= 4. 31 IF NTIME=85 THEN INTRED$H= 4. 31 IF NTIME=86 THEN INTRED$H= 5. 26 IF NTIME=87 THEN INTRED$H= 5. 49 IF NTISE=88 THEN INTRED$H= 8. 2 IF NTIME=89 THEN INTRED$H= 10 .33 IF NTIME=90 THEN INTRED$H= 1. 42 LOLDMSH - STOCK OF DEBT ISSUED PRIOR TO 1976 THAT MATURES EACH YEAR IF NTIME=75 THEN LOLDM$H=0. IF NTIME=76 THEN LOLDM$H=29.4 IF NTIME=77 THEN LOLDM$H=50.1 IF NTIME=78 THEN LOLDM$ H=0. IF NTIME=79 THEN LOLDM$H=18.4 IF NTIME=80 THEN LOLDM$H=59. 1 IF NTIME=81 THEN LOLDM$H=67.9 IF NTIME=82 THEN LOLDM$H=187, 3 IF NTIME=83 THEN LOlDM$H=0. IF NTIME=84 THEN LOLDM$H=50. IF NTIME=85 THEN LOLDM$H=50. IF NTIME=86 THEN LOLDM$H=124. 4 IF NTIME=87 THEN LOLDM$H=105.4 IF NTIME=88 THEN LOLDM$H=156.3 IF NTIME=89 THEN LOLDM$H=155.3 IF NTIME=90 THEN LOLDM$H=21.9 LMATWOSF - SHORTFALL IN SINKING FUND FOR BONDS MATURING AFTER 1981 LMATHOSF=0. IF NTIHE=82 THEN LMATWGSF=93.2 IF NTIME=86 THEN LMATWOSF=104.2 IF NTIME=87 THEN LMATWOSF=60.3 IF NTIME=88 THEN LMAT¥OSF=81.9 IF NTIME=89 THEN LMAT¥OSF=104.8 IF NTIME=90 THEN LMATHOSF=9.2 COVERAGE - INTEREST COVERAGE POLICY COEFFICIENT IF NTIME=75 THEN COVERAGES. IF NTIME=76 THEN COVERAGES. IF NTIME=77 THEN COVERAGE^.04 IF NTIME=78 THEN COVERAGE-.08 IF NTIME=79 THEN COVERAGE^.12 IF NTIME=80 THEN COVERAGE^. 16 154 IF NTIME=81 THEN C0VERAGE=.2 IF NTIME=82 THEN COVERAGE=.24 IF NTIME=83 THEN COV ERAG E=.28 IF NTIME>=84 THEN CGVERAGE=.3 RESRED - RES. DEMAND CHANGE DOE TO MARG. PRICE CHANGE RESRED=(A{2013) + A(2014)- (A (201 9) * (A (20 14)-A (20 13} ) ) ) / (A (2019) * (A (2014)-A (2013)) +A (2013) +A (2014) ) GENRED - GENERAL DEMAND CHANGE DUE TO MARGINAL PRICE CHANGE GENRED=(A(2015) +A (2016)- (A (2020) * (A (20 16)-A (20 15) ) ) ) / (A(2020) *(A(2016)-A(2015))*A(2015)+A (2016)) BULK DEMAND CHANGE DUE TO MARGINAL PRICE CHANGE BULKRED= (A (2017) +A (2018) - (A (2021) * (A (2 01 8) -A (2017) ) ) ) / (A(2021) * (A{2018)-A (2017)) «-A(2017) *A(2018) ) TOTRED - WEIGHTED DEMAND CHANGE DUE TO MARGINAL PRICE CHANGE TOTRED=((RESEED*DRES)+(GENRED*DGEN)+ (BULKRED*DBULK))/(DRES+DGEN+DBULK) SUBROUTINE MCOST CHECK FOR CRITICAL RAINFALL PERIOD IF A(2007) NOT= 0. THEN GO TO 20 SENERC - TOTAL NEW ENERGY GENERATION CAPABILITY DURING AVERAGE RAINFALL PERIOD SENERC=SENERHAC + SENERBAC+SENERCAC+ SENERKAC+SENERGAC- 796. GO TO 40 SENERC - TOTAL NEW ENERGY GENERATION CAPABILITY DURING CRITICAL RAINFALL PERIOD 20 SENERC=SENERHCC + SENERBAC+SENERCAC+SENERKAC+SEN ERGAC- 9. SCAP - TOTAL NEW CAPACITY CAPABILITY 40 SCAP=SCAPH+SCAPB*SCAPC+SCAPK+SCAPG-5413. IF A(2010)>30. THEN GO TO 50 IF A (2011)>10. THEN GO TO 50 HERE IF A HYDRO PROJECT NLIFE - EXPECTED PHYSICAL LIFE OF PROJECT NLIFE=70 COPS76 - ANNUAL OPERATING COSTS OF PROJECT ($76) COP$76=A (1853)*KPISH$76 +A(1856)*KPST1$76 + A (1861)*SENERC+A(1860)*SCAP GO TO 100 50 IF A(2010)>35. THEN GO TO 60 IF A (2011) >15. THEN GO TO 60 155 HEBE I F A GAS TURBINE PROJECT COP$76=A (1855) *KPISG$76 + A (18 56) *KPST1$76+A (1 865} * SENEBC GO TO 90 60 IF A(2010)>43. THEN GO TO 70 IF A(2011)>20. THEN GO TO 70 HERE I F HAT CREEK COAL COP$76=A (1854)*KPISC$76+A(1856)*KPST1$76 + A(1862) * SENERC GO TO 90 HERE I F EAST KOOTENAY COAL 70 COP$76 = A(1854) *KPISK$76 + A ( 1856) *KPST1$76+A (1863) * SENERC 90 NLIFE=35 100 RLIFE=NLIFE QSTABT EQUAL 1 IF NEW PROJECT IS PRODUCING ENERGY IF (SENERC+SCAP)>0. THEN QSTART=1. NSTOP - TIME WHEN PROJECT'S LIFE IS OVER IF (QSTART-J1L*QSTART)=1. THEN NSTOP=NTIME+NLIFE-75 IF K7>NSTOP THEN COP$76=0. RSTART - TIME WHEN NEW PROJECT BEGINS PRODUCING ENERGY IF QSTART=0. THEN BSTABT=0., IF (QSTART-J1L*QSTART) = 1. THEN RSTART=RTIME KPVELEC1 - PRESENT VALUE OF POTENTIAL ENERGY PRODUCED (KWH) DURING LIFE OF PROJECT BEING ANALYZED KPVELEC1=(1.+A(1894} ) *J1L*KPVELEC1+SENEEC*({1.+A{1894))**.5) KPVELEC2 - PRESENT VALUE OF POTENTIAL CAPACITY GENEBATED(MW) DUBING LIFE OF PROJECT BEING ANALYZED KPVELEC2=(1.*A(1894))*J1L*KPVELEC2+SCAP*((1.+A(189 4 ) ) * * . 5) IF QSTART=0. THEN GO TO 110 IF K7=NSTOP THEN KPVELEC1=KPVELEC1/((1.*A(1894))**(K7-2)) IF K7>NSTOP THEN KPVELEC1=0. IF K7=NSTOP THEN KPVELEC2=KPVELEC2/((1.+A(1894))**(K7-2)) IF K7>NSTOP THEN KPVELEC2=0. DETERMINE TYPE OF DEPRECIATION BEING USED 110 IF A(1850)>=1. THEN GO TO 120 HERE I F EXPONENTIALLY DECLINING DEPRECIATION CHARGE BASED ON AVERAGE ECONOMY-WIDE SESVICE LIFE KELEC - STOCK OE CAPITAL ASSOCIATED WITH PROJECT 156 KELEC=(J1L*KELEC+IGEN$76*ITRS1$76)* (1.- (QSTART*A{1850) ) ) KPVC1$76 - PRESENT VALUE OF COSTS ASSOCIATED WITH PROJECT BEING ANALYZED KPV1$76= (1.+A{1894)) *J11*KPV1$76+(COP$76+ (A(1850)* (J1L*KELEC+IGEN$76+ITRS1$76) ) • ( (A (1890) +A (1895) ) *. 5* (J1L * K EL EC • K EL EC) ) ) * ((1.«-A(1894) )**.5) GO TO 200 HERE IF STRAIGHT-LINE DEPRECIATION CHARGE BASED ON ACTUAL LIFE 0 PROJECT BEING ANALYZED 120 IF A (1850) =1. THEN A (1850)-RLIFE IF RSTART=0. THEN GO TO 125 IF A (1850) <= (RTIME-RSTART) THEN GO TO 130 125 KELEC=(J1L*KELEC+IGEN$76+ITRS1$76)* (1.-(QSTART/(A(1850)-(RTIME-RSTART)))) KPV1$76=(1.+A(1894)) *J1L*KPV1$76+(COP$76+(QSTART/ (A(1850)-(RTIME-RSTART))*{J1L*KELEC+IGEN$76+ITRS1$76)) ({A (1890) + A(1895)) *.5*(J1I*KELEC*KELEC)) )* ( (1.+A (1894) ) **.5) GO TO 200 HERE I F PROJECT LIFE FOR DEPRECIATION PURPOSES IS OVER 130 KELEC=0. KPV1$76= (1.+A(1894))*J1L*KPV1$76+ (COP$76*((A(1890)+A(1895))*.5*(J1L*KELEC+KELEC) ) )* ( (1.+A(1894))**.5) 200 IF QSTART=0. THEN GO TO 210 IF K7=NSTOP THEN KPV1$76=KPV1$76/((1.+A{1894))**(K7-2)) IF K7>NSTOP THEN KPV1$76=0. PKWHCST1 - 1976$ PRESENT VALUE COST PER KWH ENERGY CAPACITY FOR PROJECT BEING ANALYZED IF K7=8STOP THEN PKWHCST1=KPV1$76/KPVELEC1 IF K7>NSTOP THEN PKWHCST1=0. PWCOST1 - 1976$ PRESENT VALUE COST PER WATT CAPACITY CAPABILITY FOR PROJECT BEING ANALYZED IF K7=NSTOP THEN PWCOST1=KPV1$76/KPVELEC2 IF K7>NSTOP THEN PWCOST1=0. SUBROUTINE APPROVE 157 THIS SECTION SETS APPROVAL DATES FOR PRESENTLY UNCOMMITTED MAJOR GENERATION AND TRANSMISSION PROJECTS BY COMPARING EXPECTED ENERGY AND CAPACITY REQUIREMENTS WITH PRESENTLY COMMITTED ENERGY AND CAPACITY CAPABILITY. ENERGY AND/OR CAPACITY IS BROUGHT ON STREAM IN AN INCREASING COST SEQUENCE TO MEET THIS ANTICIPATED DEMAND. DTOTF DTGTF= DTOTF DGROSSF DGROSSF=DGROSSF DPEAKF DPEAKF=DPEAKF HERE I F RATE STRUCTURE CHANGE AFFECTS DTOTF IF A{2012) = 1. THEN DT OT F= R ES R ED* DR ES F • GENRED*DGENF*-BULKBED*DBULKF*DW KPLF IF A (2012) NOT= 1. THEN DTOTF=DRESF + DGENF+DBULKF + DWKPLF DTOTF - ADJUST EXPECTED TOTAL NET DEMAND BY DEMAND SHOCK IF RTIME>=(A<1867)-6.) THEN DTOTF= DTOTF*A (1866) DGROSSF - APPLY LOSS FACTOR TO DETERMINE TOTAL GROSS DEMAND SIX YEARS HENCE DGROSSF=DTOTF+.2527+(.1107*DTOTF) A(18 86) - SET GROSS DEMAND SHOCK A(1886) = 1. 1107*A(1866) DPEAKF - EXPECTED PEAK DEMAND SIX YEARS HENCE DERIVED FROM LOAD FACTOR APPLIED TO EXPECTED DEMAND IF A{1885)=0. THEN GO TO 1 IF RTIME<(A(1887)—6.) THEN DPEAKF=DGROSSF/ (A(1849)*.0876) IF RTIME>= (A (1887)-6.) THEN DPEAKF=(DGROSSF-A( 1886))/ (A (1849) *.0876) + A (1886) / {A (1885) *.0876) GO TO 2 HERE I F DEMAND SHOCK HAS NO EFFECT ON PEAK DEMAND 1 IF RTIME< (A (1887)-6. ) THEN DPEAKF= DGROSSF/ (A(1849)*.0876) IF RTIME>=(A(1887)-6.) THEN DPEAKF=(DGROSSF-A(1886))/ (A (1849) *.0876) CARRY FORWARD APPROVAL DATES FOR EACH PROJECT 2 DO 3 1=429,470 3 STARG?=J1L*STARG? DO 4 1=477,485 4 START?=J1L*START? SECNEW - INITIALIZE NEW ENERGY CAPACITY VARIABLE SECNEW=0. 158 SENCAPF - EXPECTED ENERGY GENERATION CAPACITY SIX YEARS HENCE ON BASIS OF PROJECTS APPROVED TO DATE IF NTIME=75 THEN SENCAPF=41349. IF NTIME>75 THEN SENCAPF=J1L*SENCAPF+(.5*J1L*SECNEW) SCAPF - EXPECTED CAPACITY CAPABILITY SIX YEARS HENCE ON BASIS OF PROJECTS APPROVED TO DATE IF NTIME=75 THEN SCAPF=8488. IF NTIME>75 THEN SCAPF=J1L*SCAPF SEE I F DEMAND IS AT THE LEVEL REQUIRING INSTALLATION OF GAS TURBINES ON VANCOUVER ISLAND IF J1L*DTOTF>37000. THEN GO TO 5 IF DTOTF<37000. THEN GO TO 10 STARG31=RTIME+5. START31=RTIME+4. SECNEW=SECNEW+657. SENCAPF=SENCAPF+ (.5*657.) SCAPF=SCAPF+150. 5 IF J1L*DTOTF>41000. THEN GO TO 10 IF DTOTF<41000. THEN GO TO 10 STARG32=RTIME+5. SECNEW=SECNEW+657. SENCAPF=SENCAPF+(.5*657.) SCAPF=SCAPF+150. SET APPROVAL DATES FOR VARIOUS INCREASINGLY COSTLY ENERGY GENERATION AND ASSOCIATED TRANSMISSION PROJECTS BASED ON COMPARING EXPECTED ENERGY GENERATION CAPACITY (FROM PREV- IOUSLY APPROVED PROJECTS) DURING CRITICAL RAINFALL PERIODS WITH EXPECTED GROSS ENERGY DEMAND LEVELS, AND ADJUSTING TO INCORPORATE THE DIFFERENT CONSTRUCTION PERIODS REQUIRED. 10 IF NTIME NOT= 78 THEN GO TO 20 STARG12=RTIME+4. SECNEW=SECNEW+875. SENCAPF=SENCAPF+ (.5*875.) 20 IF SENCAPF>=DGROSSF THEN GO TO 500 IF NTIME<=78 THEN GO TO 30 IF STARG14>0. THEN GO TO 30 STARG14=RTIME SECNEl=SECNEW+2750. SENCAPF=SENCAPF+(.5*2750.) IF SENCAPF>=DGROSSF THEN GO TO 500 30 IF STARG9>0. THEN GO TO 40 STARG9=RTIME START9=RTIME SECNEW=SECNEW+4773. , SENCAPF=SENCAPF+(.5*4773.) SCAPF=SCAPF+900. IF SENCAPF>=DGROSSF THEN GO TO 500 40 IF STARG10>O. THEN GO TO 50 STARG10=RTIME+1. IF STARG10>(STARG9+2.) THEN STARG10=STARG9+2. START10=STARG10 SECNEW=SECNEW+1634. . SENCAPF=SENCAPF+{.5*1634.) SCAPF=SCAPF+450. 159 IF SENCAPF>=DGROSSF THEM GO TO 500 50 IF STARG11>0. THEN GO TO 60 STARG11=RTIME+2. SECNEW=SECNEW+484. IF STARG11>(STARG10+1. ) THEN STARG11=STARG10+1. SENCAPF=SENCAPF+(.5*484.) SCAPF=SCAPF+450. IF SENCAPF>=DGROSSF THEN GO TO 500 60 IF STARG36>0. THEN GO TO 70 STARG36=BTIME START36=RTIME SECNEW=SECNE8+3420. SENCAPF=SENCAPF+(.5*3420. ) SCAPF=SCAPF+500. IF SENCAPF>=DGROSSF THEN GO TO 500 70 IF STARG37>0. THEN GO TO 80 STARG37=RTIME+1. SEC N Ew= SECNES+3420. SE NC APF= SENC APF+ (.5*342 0. ) SCAPF=SCAPF+5O0. IF SENCAPF>=DGROSSF THEN GO TO 500 80 IF STARG38>0. THEN GO TO 90 STARG38=HTIME*1. START38= RTIME+1 . SECNEW=SECNE5J*3420. SENCAPF=SENCAPF+ (.5*3420.) SCAPF=SCAPF+500. IF SENCAPF>=DGROSSF THEN GO TO 500 90 IF STABG39>0. THEN GO TO 130 STARG39=RTIME+1. SECNEw=SECNEH+3420. SENCAPF=SENCAPF+ (. 5*3420.) SCAPF=SCAPF+500. IF SENCAPF>=DGROSSF THEN GO TO 500 130 IF STABG40>0. THEN GO TO 140 STARG40=RTIME START40=RTIME SECNEB=SECNEw+4790. SENCAPF=SENCAPF+(.5*4790.) SCAPF=SCAPF+700. IF SENCAPF>=DGROSSF THEN GO TO 500 140 IF STARG41>0. THEN GO TO 150 STARG41=RTIME*1. SECNElg=SECNEw+4790. SENCAPF=SENCAPF+(.5*479 0.) SCAPF=SCAPF+700. IF SENCAPF>=DGROSSF THEN GO TO 500 150 IF STARG42>0. THEN GO TO 160 STARG42=RTIME+1. SECNEW=SECNES+4790. SENCAPF=SENCAPF+(.5*4790.) SCAPF=SCAPF+700. IF SENCAPF>=DGROSSF THEN GO TO 500 160 IF STARG43>0. THEN GO TO 170 STARG43=RTIME+1. SECNEW=SECNEW+4790. SENCAPF=SENCAPF+(.5*4790.) SCAPF=SCAPF+700. IF SENCAPF>=DGROSSF THEN GO TO 500 170 IF STARG46>0. THEN GO TO 180 160 STARG46=RTIME STABT44=RTIME SECNEW=SECNEW+4790. SENGAPF=SENCAPF* (.5*4790.) SCAPF=SCAPF+700. IF SENCAPF>=DGROSSF THEN GO TO 500 180 IF STARG45>0. THEN GO TO 190 STARG45=RTIME START45=RTIME*2. SECNEW=SECNEW*4790. SENCAPF=SENCAPF+ (. 5*4790.) SCAPF=SCAPF+700. IF SENCAPF>=DGROSSF THEN GO TO 500 190 IF STARG21>0. THEN GO TO 200 STARG2 T=RTIME STABT21=BTIME+2 . SECNEW=SECNEW+27Q2. SENCAPF^SENCAPF*(.5*2702.) SCAPF=SCAPF*450. IF SENCAPF>=DGBOSSF THEN GO TO 500 200 IF STABG22>0. THEN GO TO 210 STARG22=RTIME+2. IF STARG22>(STABG21+3.) THEN STARG22= STARG21+3. SECNEW=SECNEW+1143. SENCAPF=SENCAPF+ (-5*114 3.) SCAPF=SCAPF+225. IF SENCAPF>=DGBOSSF THEN GO TO 500 210 IF STARG23>0. THEN GO TO 500 STABG23=BTIME+2. IF STARG23>STARG22 THEN STARG23=STARG22 SECNEW=SECNEW*613. SENCAPF=SENCAPF* (.5*613.) SCAPF=SCAPF+225. RESHARD - DETERHINE DESIBED BESEBVE CAPACITY MABGIN SIX YEARS HENCE BASED ON LGSS-OF-LOAD PROBABILITY METHOD RESULTS FOR EXPECTED NATURE OF GENERATION SYSTEM 500 IF STARG36=0. THEN RESMARDF=.09 IF STARG36>0. THEN RESMABDF=.10 IF STARG37>0. THEN BESMABDF=.11 IF STARG38>0. THEN RESMARDF=.115 IF STARG39>0. THEN BESMABDF=.12 IF STARG4O0. THEN RESMABDF=. 125 IF STARG41>0. THEN RESMARDF=.1325 IF STARG42>0. THEN RESMARDF=.14 IF STARG46>0. THEN RESMARDF=.145 SCAPDF - DESIRED CAPACITY CAPABILITY SIX YEARS HENCE SCAPDF=DPEAKF*(1.+RESMARDF) SET APPROVAL DATES FOR VARIOUS INCREASINGLY COSTLY CAPACITY-PROD- UCING PROJECTS BASED ON COMPARING EXPECTED CAPACITY CAPABILITY FROM PBEVIOOSLY APPBOVED PBOJECTS WITH EXPECTED DESIBED CAPACITY, AND ADJUSTING TO INCOBPOSATE THE VARYING CONSTRUCTION PERIODS. IF SCAPF>=SCAPDF THEN GO TO 1000 IF STARG13>0. THEN GO TO 510 STARG13=RTIME*3. SCAPF=SCAPF+275. 161 IF SCAPF>=SCAPDF THEN GO TO 1000 510 IF STARG16>0. THEN GO TO 520 STARG16=RTIHE+2. SCAPF=SCAPF+4Q0. IF SCAPF>=SCAPDF THEN GO TO 1000 520 IF STARG17>0. THEN GO TO 530 STARG17=RTIME+2. SCAPF=SCAPF+400. IF SCAPF>=SCAPDF THEN GO TO 1000 530 IF STARG18>0. THEN GO TO 540 ST ARG18= RTIHE+2. SCAPF=SCAPF+450. IF SCAPF>=SCAPDF THEN GO TO 1000 540 IF STARG19>0. THEN GO TO 550 ST ABG19=RTIME+2. SCAPF=SCAPF+450. IF SCAPF>=SCAPDF THEN GO TO 1000 550 IF STARG20>0. THEN GO TO 560 STARG20=RTIME+2. SECNEW=SECNEW+65. SENCAPF=S£NCAPF+(.5*65.) SCAPF=SCAPF+175. IF SCAPF>=SCAPDF THEN GO TO 1000 560 IF STARG33>0. THEN GO TO 570 ST ARG33=RTIME+5. SECNEW=SECNEB+657. SENCAPF=SENCAPF+(.5*657.) SCAPF=SCAPF+150. IF SCAPF>=SCAPDF THEN GO TO 1000 570 IF STARG34>0. THEN GO TO 580 STARG34=RTIKE+5. SECNEB=SECNEW+1314. SENGAPF=SENCAPF+{.5*1314.) SCAPF=SCAPF*300. IF SCAPF>=SCAPDF THEN GO TO 1000 580 IF STARG35>0. THEN GO TO 1000 STARG35=RTIME+5. SECNEW=SECNE»*2628. SENCAPF=SENCAPF+ (.5*2628.) SCAPF=SCAPF+600. 1000 SECNEB=SECNEB SUBROUTINE SUPPLY THIS SECTION TAKES INFORMATION ON DEMAND GROWTH FORECASTS AND DETERMINES THE QUANTITY AND COST OF FACILITIES THAT SHOULD BE BUILT ITRS2$76 - INVESTMENT IN NON-ASSOCIATED MAJOR TRANSMISSION PROJECTS IF NTIME=75 THEN ITRS2$76=15. IF NTIME>=76 THEN ITRS2$76=A (2000) * (DPEAK-J1L*DPEAK) ITRS3$76 - INVESTMENT IN SUE-TRANSMISSION LINES 162 IF NTIME=75 THEN ITRS3$76=10. IF NTIME>=76 THEN ITRS3$76=A (20Q 1) * (DPEAK-J1L*DPEAK) ITRF1$76 - INVESTMENT IN TRANSMISSION TRANSFORMATION IF NTIHE=75 THEN ITRF1$76=5. IF NTIME>=76 THEN ITRF1$76=A{2002)*(DPEAK-J1L*DPEAK) ITRF2$76 - INVESTMENT IN SUB-TRANSMISSION TRANSFORMATION I F NTIME=75 THEN ITRF2$76=20. IF NTIME>=76 THEN ITRF2$76=A(2003)*(DPEAK-J1L*DPEAK) IDST1$76 - INVESTMENT IN DISTRIBUTION FACILITIES FOR NEB CUSTOMERS IF NTIME=75 THEN IDST1$76=50. IF NTIME>=76 THEN IDST1$76=A(2004)*(NOCUST-J1L*NOCUST) IDST2$76 - INVESTMENT IN DISTRIBUTION FACILITIES FOR GROWTH BY EXISTING CUSTOMERS IF NTIME=75 THEN IDST2$76=10. , IF NTIME>=76 THEN IDST2$76=A (2005) * (DPEAK-J1L*DPEAK) IMISCS76 - INVESTMENT IN OTHER ELECTRIC PLANT IF NTIME=75 THEN IMISC$76=6. IF NTIME>=76 THEN IMISC$7 6= A (2006)*(DTOT—J1L*DT0T) SET ANY NEGATIVE INVESTMENT TO ZERO IF ITRS2$76<0. THEN ITRS2$76=0. IF ITSS3$76<0. THEN ITRS3$76=0. IF ITRF1$76<0. THEN ITRF1$76=0. IF ITRF2$76<0. THEN ITRF2$76=0. IF IDST1$76<0. THEN IDST1$76=0. IF IDST2$76<0. THEN IDST2$76=0. IF IMISC$76<0. THEN IMISC$76=0. ITRS$74 - INVESTMENT IN MAJOR TRANSMISSION AND SUB-TRANSMISSION PROJECTS ITRS$76=ITRS1$76-HTRS2$76+ITRS3$76 ITRF$76 - INVESTMENT IN TRANSFORMATION ITRF$76=ITRF1$76+ITRF2$76 IDIST$76 - INVESTMENT IN DISTRIBUTION FACILITIES IDIST$76=IDST1$76+IDST2$76+IMISC$76 KPISHSH - NEW HYDRO PLANT IN SERVICE KPISH$H=KPISH$H KPISCSH - NEW COAL GENERATION PLANT IN SERVICE KPISC$H=KP1SC$H KPISGSH - NEW GAS TURBINES IN SERVICE KPISG$H=KPISG$H KPISTSSH - MAJOR TRANSMISSION AND SUB-TRANSMISSION PLANT IN SERVICE ($H) 163 KPISTS$H=KPIST1$H+KPIST2$H KPISTSH - TRANSMISSION AND TRANSFORMATION PLANT IN SERVICE ($H) KPIST$H=KPIST1$H+KPIST2$H+KPISTF$H 1$ - INVESTMENT IN CURRENT DOLLARS I$=IGEN$+ITRS1$+ (PEXOG/2. 11 * (ITRS2$76 + ITRS3$76+ITRF1$76+ITRF2$76+IDST1$76+IDST2$76+ IMISCS76)) KPIST2$76 - NEW NON-ASSOCIATED TRANSMISSION AND SUB-TRANSMISSION PLANT IN SERVICE {$76) KPST2$76=J1L*KPST2$76+ITRS2$76+ITRS3$7 6 KPSTF$76 - NEW TRANSFORMATION PLANT IN SERVICE ($76) KPSTF$76=J1L*KPSTF$76+ITRF1$76+ITSF2$76 KEIST$76 - ALL NEW TRANSMISSION AND TRANSFORMATION PLANT IN SERVICE ($76) KPIST$76=KPST1$76+KPST2$76*KPSTF$76 KPST3$76 - ALL NEW TRANSMISSION AND TRANSFORMATION PLANT IN SERVICE ($76) TO SERVE CUSTOMERS AT THE 230 KV LEVEL KPST3$76=J1L*KPST3$76+ITRS2$76+ITRS3$76+ITRF1$76+ KPST1$76-J1L*KPST1$76 KPST3$76=KPST3$76 KPST4$76 - STOCK OF NEW SUB-TRANSMISSION TRANSFORMATION PLANT IN SERVICE ($76) KPST4$76=J1L*KPST4$76+ITRF2$76 KPISD$76 - NEW DISTRIBUTION PLANT IN SERVICE ($76) KPISB$76=J1L*KPISD$76+IDST1$76+IDST2$76+IMISC$76 KPISM$76 - NEW MISCELLANEOUS PLANT IN SERVICE ($76) FOR 230 KV LEVEL CUSTOMERS KPISM$76=J1L*KPISM$76+(.5*IMISC$76) KPIS$76 - TOTAL NEW PLANT IN SERVICE ($76) KPIS$76=KPISH$76*KPISG$76+KPISC$76+KPISK$76+ KPIST$76+KPISD$76 KPIST2$H - NEW NON-ASSOCIATED MAJOR TRANSMISSION AND SUBTRANS- MISSION PLANT IN SERVICE ($H) KPIST2$H=JTL*KPIST2$H*(PEXOG/2.11*(ITRS2$76*ITRS3$76) *A(1851)) KPISTF$H - NEW TRANSFORMATION PLANT IN SERVICE ($H) KPISTF$H=J1L*KPISTF$H*- (PEXOG/2. 1 1* (ITRF1$76 + ITRF2$76)*A(1852)) KPISDSH - NEW DISTBIfiOTIOH PLANT IN SERVICE ($H) 164 KPISD$H=*J1L*KPISD$H+ {PEXOG/2. 1 1* (IDST1 $76+IDST2$76 * IMISC$76)) RESMARD - DESIRED RESERVE CAPACITY MARGIN DERIVED FROM LOSS-OF-LOAD PROBABILITY OF ONE DAY IN TEN YEARS IF SCAPBX6100. THEN RESMARD=.10 IF SCAPH>=6100. THEN RESMARD=.095 IF SCAPH>=6400. THEN RESMARD=.09 IF SCAPOO. THEN RESMARD=. 10 IF SCAPC>=500. THEN RESMARD=.105 IF SCAPC>=1000. THEN BESMABD=.11 IF SCAPC>=1500. THEN RESMARD=.115 IF SCAPC>=2000. THEN BESMABD=.12 IF SCAPC>=2500. THEN BESMARD=.125 IF SCAPC>=3000. THEN RESMABD=.13 IF SCAPC>=3500. THEN RESMARD=. 135 IF SCAPC>=1*000. THEN RESMARD=. 14 IF SCAPK>0. THEN RESMARD=.145 SCAPD - DESIRED CAPACITY CAPABILITY (INCLUDES DESIRED RESERVE CAPACITY MARGIN) SCAPD=DPEAK*(1. +RESMARD) SCAP - ANNUAL CAPACITY CAPABILITY SCAP=SCAPH*SCAPB+SCAPC+SCAPK+SCAPG SCAPSURP - SURPLUS (DEFICIT) OF ACTUAL CAPACITY CAPABILITY OVER DESIRED CAPACITY CAPABILITY SCAPSURP=SCAP-SCAPD RESMAB - ACTUAL RESERVE CAPACITY MARGIN RESMAR=(SCAP-DPEAK) /DPEAK DETERMINE ACTUAL ENERGY PRODUCED FROM EACH SOURCE SENERH - ACTUAL ENERGY PRODUCED FROM HYDRO SOURCES SENEBH=DGBOSS SENERC - ACTUAL ENERGY PRODUCED FROM HAT CREEK COAL SENERC=0. IF DGROSS>SENERHC THEN SENERC=DGROSS-SENERHC IF DGROSS>(SENERHC+SENEECC) THEN SENERC=SENERCC SENERK - ACTUAL ENERGY PRODUCED FROM EAST KOOTENAY COAL SENERK=0. IF DGROSS>(S ENERHC+S ENERCC) THEN SENERK=DGROSS- SENERHC—SENERCC IF DGROSS>(SENERHC+SENERCC + SENERKC) THEN SENERK=SENERKC SENERB - ACTUAL ENERGY PRODUCED AT BURRARD SENERB=0. IF DGROSS>(SENERHC+SENERCC+SENERKC) THEN SENERB= DGROSS—SENERHC—S ENERCC—SENERKC IF DGROSS>(SENERHC+SENERCC+SENERKC*SENERBC) THEN SENERB= SENERBC SENERG - ACTUAL ENERGY PRODUCED FROM GAS TURBINES SENERG=0. IF DGROSS>(SENERHC+SENERCC+SENERKC+SENERBC) THEN SENERG= DGROSS-S ENER HC-S ENERCC-SENERKC-SEN ER BC IF DGROSS>{SENERHC + SENERCC + SENERKC*SEN ERBC + SENERGC) THEN S ENERG=SENERGC SENERM - ACTUAL ENERGY IMPORTED FROM OTHER UTILITIES SENERM=0. IF DGROSS>(SENERHC+SENERCC+SENERKC+SENERBC* SENERGC) THEN S ENERM=DGROSS-SENER HC-SEN ERCC-SENER KC -SENERBC-SEN ERGC IF SENERM>0. THEN GO TO 200 SENEREXP - ACTUAL ENERGY EXPORTED TO OTHER UTILITIES B C HYDRO SEEKS TO EXPORT ELECTRICITY WHEN GROSS DOMESTIC DEMAND IS LESS THAN ENERGY GENERATION CAPACITY AND VARIABLE OPERATING COSTS ARE BELOl EXPORT PRICES. THE EXTENT TO WHICH IT FINDS A MARKET FOR ANY ECONOMICALLY SURPLUS POWER IS DETERMINED BY THE FRACTION SET BY A (1873) IF A (1863) >=A (1879) THEN GO TO 100 DEXPORT=A(1873)*(SENERHC*SENERCC*SENERKC—DGROSS) 166 IF DEXPORT<0. THEN DEXPORT=0. IF DEXPORT=0. THEN GO TO 200 IF A {1862) <A {1879) THEN GO TO 20 DEXPORT=A{1873) * (SENERHC+SENERKC-DGROSS) IF DEXPORT<0. THEN DEXPORT=0. IF DEXPORT=0. THEN GO TO 200 DIFFH=SENERHC-SENERH IF DIFFH<=0. THEN GO TO 10 S EN E R H= S EN E R H + DEXPORT IF SENERH<SENERHC THEN GO TO 200 SENERH=SENERHC SENERK=SENERK+DEXPORT-DIFFH GO TO 200 10 SENERK=SENERK+DEXPORT GO TO 200 20 DIFFH=SENERHC-SENERH DIFFC=SENERCC-S ENERC IF DIFFH>0. THEN GO TO 30 IF DIFFOO. THEN GO TO 40 SENERK=SENERK*DEXPORT GO TO 200 30 SENERH=SENERH+DEXPORT IF SENERH>SENERHC THEN GO TO 50 GO TO 200 4 0 SENERC=SENERC+DEXPORT IF SENERC<SENERCC THEN GO TO 200 SENEBC=SENERCC SENERK=SENERK+DEXPORT-DIFFC GO TO 200 50 SENERH=SENERHC SENERC=SENERC+DEXPORT-DIFFH IF SENERC<SENERCC THEN GO TO 200 SENERC=SENERCC SENERK=SENERK+DEXPORT-DIFFH-DIFFC GO TO 200 100 DEXPORT=A(1873)*<SENERHC+SENERCC-DGROSS) IF DEXPORT<0. THEN DEXPORT=0. 167 IF DEXPGRT=G. THEN GO TO 200 IF A (1862) <A (1879) THEN GO TO 110 DEXPORT=SEN EBHC-DGBOSS IF DEXPORT<0. THEN DEXPOBT=0. IF DEXPORT=0. THEN GO TO 200 SENEBH=SENEBH+DEXPOET GO TO 200 110 DIFFH=SENERHC-SENERH IF DIFFH>0. THEN GO TO 120 SENERC=SENERC+DEXPORT GO TO 200 120 SENERH=SENEBH+DEXPOBT IF SENERH<SENERHC THEN GO TO 200 SENEBH=SENEBHC SENERC=SENERC+DEXPOBT-DIFFH GO TO 200 SENER - TOTAL ENERGY GENERATED 200 SENER=SENEEH+ SENERC + SENERK +SENERB + SENERG THIS SECTION TAKES INFORMATION FROM POLS1 ON APPROVAL DATES FOR MAJOR GENERATION AND TRANSMISSION PROJECTS AND CALCULATES ANNUAL CAPITAL INVESTMENT (INCLUDING INTEREST DURING CONSTRUCTION) THAT BESULTS. IT ALSO CALCULATES ADDITIONS TO PLANT IN SEBVICE AND THE NEW ENERGY (CBITICAL AND AVEBAGE) AND CAPACITY CAPABILITIES FOLLOWING THE COMPLETION OF THESE NEW PROJECTS. INITIALIZE SUBBOUTINE-SPECIFIC VARIABLES TO ZERO FOR: VARIOUS CATEGORIES (HYDRO,HAT CREEK,EAST KOOTENAY,GAS TURBINE, TRANSMISSION) OF POST-74 PLANT IN SERVICE ($76) PH$76=0. PC$76=0. PK$76=0. PG$76=0. PT$76=0. VARIOUS CATEGORIES OF POST-74 PLANT IN SERVICE ($H) PH$H=0. PC$H=0. PK$H=0. PG$H=0. PT$H=0. 168 HYDRO-ELECTRIC ENERGY CAPABILITY DURING CRITICAL RAINFALL PERIODS SEHCC=0. VARIOUS CATEGORIES OF AVERAGE ENERGY CAPABILITY SEHAC=0. SECAC=0. SEKAC=0. SEGAC=0. VARIOUS CATEGORIES OF GENERATION CAPACITY CAPABILITY SCH=0. SCC=0. SCK=0. SCG=0. CAPITAL EXPENDITURES ($76) FOR EACH GENERATION PROJECT G1$76=0. G2$76=0. G3$76=0. G4$76=0. G5$76=0. G6$76=0. G7$76=0. G8$76=0. G9$76=0. G10$76=0. G11$76=0. G12$76=0. G13$76=0. G14$76=0. G15$76=0. G16$76=0. G17$76=0. . G18$76=0. G19$76=0. G20$76=0. G21$76=0. G22$76=0. G23$76=0. G24$76=0. G25$76=0. G26$76=0. G27$76=0. G2 8$76=0. G29$76=0. G30$76=0. G31$76=0. G32$76=0. G33$76=0. G34$76=0. G35$76=0. G36$76=0. G37$76=0. G38$76=0. G39$76=0. GU0$76=0. G41$76=0. G42$76=0. G43$76=0. 169 G44$76=0. G45$76=0. G46$76=0. G47$76=0. G48$76=0. G49$76=0. G50$76=0. CAPITAL EXPENDITURES ($76) FOR EACH MAJOR ASSOCIATED TRANSMISSION PROJECT T1$76=0. T2$76=0. T3$76=0. T4$76=0. T6$76=0. T8$76=Q. T9$76=0. T10$76=0. T21$76=0. T31$76=0. T36$76=0. T38$76=0. T40$76=0. T44$76=0. T45$76=0. GO TO APPROPRIATE PROJECTS IF COEFFICIENTS INDICATE AN ECONOMIC ANALYSIS OF PROJECT IS DESIRED IF A j (2011) =0. THEN GO TO 5 IF A (2011) = 1. THEN GO TO 90 IF A (2011) =2. THEN GO TO 120 IF A (2011) = 3. THEN GO TO 130 IF A (2011) =4. THEN GO TO 140 IF A (2011) =5. THEN GO TO 160 IF A (2011) = 6. THEN GO TO 80 IF A (2011) = 7. THEN GO TO 210 IF A j (2011) = 8. THEN GO TO 60 IF A (2011) -11 . THEN GO TO 310 IF A (2011] = 16 . THEN GO TO 360 IF A (2011) = 17 . THEN GO TO 400 IF A (2011] =21 . THEN GO TO 440 5 IF A (2010) = 0. THEN GO TO 10 IF A (2010) = 6. THEN GO TO 60 IF A (2010) =7. THEN GO TO 70 IF A (2010) = 8. THEN GO TO 80 IF A (2010) = 9. THEN GO TO 90 IF A (2010) = 10 . THEN GO TO 100 IF A (2010] = 11 . THEN GO TO 1 10 IF A (2010) = 12 . THEN GO TO 120 IF A (2010) = 13 . THEN GO TO 130 IF A (2010) = 14 . THEN GO TO 140 IF A (2010) = 16 . THEN GO TO 160 IF A (2010) = 17 . THEN GO TO 170 IF A (2010) = 18 . THEN GO TO 180 IF A (2010) = 19 . THEN GO TO 190 IF A (2010) = 20 . THEN GO TO 200 IF A (2010) =21 . THEN GO TO 210 IF A (2010] = 22 . THEN GO TO 220 IF A (2010) = 23 . THEN GO TO 230 IF A(2010) = 31. THEN GO TO 310 IF A (2010) = 32. THEN GO TO 320 IF A(201G) = 36. THEN GO TO 360 IF A (2010) = 37. THEN GO TO 370 IF A (2010) = 38. THEN GO TO 380 IF A (2010) = 39. THEN GO TO 390 IF A (2010) = 40. , THEN GO TO 400 IF A(2010) = 41. THEN GO TO 410 IF A(2010) =42. THEN GO TG 420 IF A (2010) = 43. THEN GO TO 430 IF A (2010) =44. THEN GO TO 440 IF A<2010) =45. THEN GO TO 450 CALCULATE FINANCIAL AND ENGINEERING INFORMATION FROM KNOWLEDGE ABOUT STARTING LATE OF EACH GENERATION PROJECT SEE STATEMENT 90 FOR EXPLANATION OF TYPICAL SET OF CALCULATIONS IN THIS SECTION 10 IF RTIME>STARG1 THEN GO TO 20 IF RTIME=STARG1 THEN G1$76=13.1*A(1901) IGl$=PEXOG/2.11*G1$76 IDCG1$=6. IDC$=IDC$+IDCG1$ 20 IF RTIME>STARG2 THEN GO TO 30 IF RTIME<STAEG2 THEN GO TO 30 IF RTIME-STARG2 THEN G2$76=4. 8*A (1 902) IG2$=PEXOG/2.11*G2$76 IDCG2$=2. IDC$=IDC$+IDCG2$ IF RTIME NOT= STARG2 THEN GO TO 30 PH$76=PH$76+(25.8*A(1902)) PH$H=PH$H+25.6 SEHCC=SEHCC-H747. SEHAC=SEHAC+1920. SCH=SCH*250. 30 IF RTIME>(STARG3+1.) THEN GO TO 40 IF RTIME=STARG3 THEN G3$76=60.5*A(1903) IF RTIME= (STAEG3 + 1. ) THEN G3$76=41. 5*A (1 903) IG3$=PEXOG/2.11*G3$76 IF RTIME=STARG3 THEN IDCG3$=13. IF RTIME= (STARG3 + 1.), THEN IDCG3$=18. IDC$=IDC$+IDCG3$ IF RTIME NOT= (STARG3+1.) THEN GO TO 40 PH$76=PH$76+(199.6*A(1903)) PH$H=PH$H+255. SEHCC=SEHCC+2386. SEHAC=SEHAC+276 0. SCH=SCH+800. 40 IF RTIME>STARG4 THEN GO TO 50 IF RTIME=STARG4 THEN G4$76=13.6*A(1904) IG4$=PEXOG/2.11*G4$76 IF RTIME=(STARG4-1.) THEN IDCG4$=3. IF RTIME=STAEG4 THEN IDCG4$=6.5 IF RTIME=(STARG4*1.) THEN IDCG4$=14. IDC$=IDC$+IDCG4$ IF RTIME NOT= STARG4 THEN GO TO 50 PH$76=PH$76+ (66.7*A (1904)) PH$H=PH$H+103.. SEHCC=SEHCC+3654. SEHAC=SEHAC+4225. SCH=SCH+800. 5 0 I F R T I M E > S T A R G 5 T H E N G O T G 6 0 1 7 1 I F R T I M E = S T A R G 5 T H E N G 5 $ 7 6 = . 2 * A ( 1 9 0 5 ) I G 5 $ = P E X O G / 2 . 1 1 * G 5 $ 7 6 I F R T I M E = ( S T A R G 5 - 3 . ) T H E N I D C G 5 $ = 1 . I F R T I M E = ( S T A R G 5 - 2 . ) T H E N I D C G 5 $ = 3 . I F R T I M E = ( S T A R G 5 - 1 . ) T H E N I D C G 5 $ = 6 . I F R T I M E = S T A R G 5 T H E N I D C G 5 $ = 1 2 . I D C $ = I D C $ + I D C G 5 $ I F R T I M E N O T = S T A R G 5 T H E N G O T O 6 0 P H $ 7 6 = P H $ 7 6 + ( 1 0 0 . * A ( 1 9 0 5 ) ) P H $ H = P H $ H + 1 7 9 . S E H C C = S E H C C + 7 0 0 . S E H A C = S E H A C + 8 1 0 . S C H = S C H + 0 . 6 0 I F R T I M E > ( S T A R G 6 + 4 . ) T H E N G O T O 6 8 I F R T I M E = S T A R G 6 T H E N G 6 $ 7 6 = 2 1 . 6 * A ( 1 9 0 6 ) I F R T I M E = ( S T A B G 6 + 1 . ) T H E N G 6 $ 7 6 = 4 6 . 9 * A { 1 9 0 6 ) I F R T I M E = ( S T A R G 6 + 2 . ) T H E N G 6 $ 7 6 = 5 3 . 4 * A ( 1 9 0 6 ) I F R T I M E = ( S T A R G 6 + 3 . ) T H E N G 6 $ 7 6 = 4 2 . 4 * A { 1 9 0 6 ) I F R T I M E = ( S T A R G 6 + 4 . ) T H E N G 6 $ 7 6 = 2 0 . 9 * A ( 1 9 0 6 ) I G 6 $ = P E X O G / 2 . 1 1 * G 6 $ 7 6 I D C G 6 $ = A ( 1 8 7 2 ) * ( { . 5 * I G 6 $ ) + J 1 L * I G 6 $ + J 2 L * I G 6 $ + J 3 L * I G 6 $ + J 4 L * I G 6 $ + J 5 L * I G 6 $ + J 6 L * I G 6 $ ) I D C $ = I D C $ + I D C G 6 $ I F R T I H E N O T = ( S T A R G 6 + 4 . ) T H E N G O T O 6 8 P H $ 7 6 = P H $ 7 6 + ( 1 8 5 . 2 * A ( 1 9 0 6 ) ) P H $ H = P H $ H * I G 6 $ + J 1 L * I G 6 $ + J 2 L * I G 6 $ + J 3 L * I G 6 $ « - J 4 L * I G 6 $ + J 5 L * I G 6 $ + J 6 L * I G 6 $ + I D C G 6 $ + J 1 L * I D C G 6 $ + J 2 L * I D C G 6 $ + J 3 L * I B C G 6 $ + J 4 L * I D C G 6 $ + J 5 L * I D C G 6 $ + J 6 L * I D C G 6 $ SEHCC=SEHCC+ 1 9 4 1 . S E H A C = S E H A C + 1 8 8 1 . S C H = S C H * 5 2 5 . , 6 8 I F A ( 2 0 1 1 ) N O T = 0 . T H E N G O T O 7 0 I F A ( 2 0 1 0 ) N O T = 0 . T H E N G O T O 5 0 5 7 0 I F R T I H E > ( S T A R G 7 + 4 . ) T H E N G O T O 7 8 I F R T I M E = S T A R G 7 T H E N G 7 $ 7 6 = 1 . * A ( 1 9 0 7 ) I F R T I M E = ( S T A R G 7 + 1 . ) T H E N G 7 $ 7 6 = 1 . 6 * A { 1 9 0 7 ) I F R T I M E = ( S T A R G 7 + 2 . ) T H E N G 7 $ 7 6 = 2 . 9 * A ( 1 9 0 7 ) I F R T I M E = ( S T A R G 7 + 3 . ) T H E N G 7 $ 7 6 = 4 . 3 * A { 1 9 0 7 ) I F R T I M E = ( S T A R G 7 + 4 . ) T H E N G 7 $ 7 6 = 5 . 9 * A { 1 9 0 7 ) I G 7 $ = P E X O G / 2 . 1 1 * G 7 $ 7 6 I D C G 7 $ = A { 1 8 7 2 ) * ( ( . 5 * I G 7 $ ) + J 1 L * I G 7 $ + J 2 I * I G 7 $ + J 3 L * I G 7 $ * J 4 L * I G 7 $ + J 5 L * I G 7 $ + J 6 L * I G 7 $ ) I D C $ = I D C $ * I D C G 7 $ I F R T I M E N O T = ( S T A R G 7 + 4 . ) T H E N G O T O 7 8 P H $ 7 6 = P H $ 7 6 + ( 1 5 . 7 * A ( 1 9 0 7 ) ) P H $ H = P H $ H + I G 7 $ + J 1 L * I G 7 $ + J 2 L * I G 7 $ + J 3 L * I G 7 $ + J 4 L * I G 7 $ * J 5 L * I G 7 $ + J 6 L * I G 7 $ + I D C G 7 $ + J 1 L * I D C G 7 $ * J 2 L * I D C G 7 $ + J 3 L * I D C G 7 $ * J 4 L * I D C G 7 $ + J 5 L * I D C G 7 $ * J 6 L * I D C G 7 $ S E H C C = S E H C C + 1 4 1 2 . S E H A C = S E H A C * 1 3 6 9 . S C H = S C H + 1 7 5 . 7 8 I F A ( 2 0 1 1 ) N O T = 0 . T H E N G O T O 5 0 5 I F A ( 2 0 1 0 ) N O T = 0 . T H E N G O T O 5 0 5 8 0 I F R T I M E > ( S T A R G 8 + 5 . ) T H E N G O T O 8 8 I F R T I M E = S T A R G 8 T H E N G 8 $ 7 6 = 9 . 7 * A ( 1 9 0 8 ) I F R T I M E = ( S T A R G 8 + 1 . ) T H E N G 8 $ 7 6 = 1 7 . 4 * A ( 1 9 0 8 ) I F R T I M E = ( S T A R G 8 + 2 . ) T H E N G 8 $ 7 6 = 3 7 . 5 * A ( 1 9 0 8 ) I F R T I M E = ( S T A R G 8 + 3 . ) T H E N G 8 $ 7 6 = 5 1 . 9 * A ( 1 9 0 8 ) I F R T I M E = ( S T A R G 8 + 4 . ) T H E N G 8 $ 7 6 = 4 1 . 6 * A ( 1 9 0 8 ) IF RTIME=(STARG8+5.) THEN G8$76=7.5*A (1908) 172 IG8$=PEXOG/2.11*G8$76 IDCG8$=A{1872)*((.5*IG8$)+J1L*IG8$+J2L*IG8$+ J3L*IG8$+J4L*.IG8$+J5L*IG8$+J6L*IG8$) IDC$=IDC$+IDCG8$ IF RTIME NOT= {STARG8+5.) THEN GO TO 88 PH$76=PH$76+(165.6*A(1908)) PH$H=PH$H+IG8$+J1L*IG8$+J2L*IG8$+J3L*IG8$+ J4L*IG8$+J5L*IG8$+J6L*IG8$*IDCG8$+J1L*IDCG8$+ J2L*IDCG8$+J3L*IDCG8$*J4L*IDCG8$+J5L*IDCG8$+J6L*IDCG8$ SEHCOSEHCC+2610. SEHAC=SEHAC + 300 4. SCH=SCH+525. SEE IF THIS PROJECT IS BEING COSTED 88 IF A{2011) NOT= 0. THEN GO TO 200 SEE I F THIS UNIT IS BEING COSTED IF A (2010) NOT= 0. THEN GO TO 505 SEE IF THIS PROJECT HAS ALREADY BEEN COMPLETED 90 IF RTIME>{STARG9-»-6.) THEN GO TO 98 DETERMINE REAL CONSTRUCTION EXPENDITURES IN THE CURRENT YEAR IF RTIME=STARG9 THEN G9$76=5. 1 *A (1 909) IF RTIME=(STARG9 + 1.) THEN G9$76= 32.7*A (1909) IF RTIME=(STARG9 + 2.) THEN G9$76=37.9*A (1909) IF RTIME= {STARG9 + 3.) THEN G9$76=73.6*A (1 909) IF RTIME=(STARG9+4.) THEN G9$76=132.1*A{1909) IF RTIME=(STARG9+5.) THEN G9$76=152.3*A{1909) IF RTIME=(STARG9 + 6.) THEN G9$76=23.*A (1909) DETERMINE NOMINAL CONSTRUCTION EXPENDITURES IN THE CURRENT YEAR IG9$=PEXOG/2.11*G9$76 CALCULATE INTEREST DURING CONSTRUCTION FOR THIS PROJECT IDCG9$=A (1872) * { (.5*IG9$) *J1L*IG9$*J2L*IG9$+ J3L*IG9$+J4L*IG9$+J5L*IG9$+J6L*IG9$) CALCULATE ALL INTEREST DURING CONSTRUCTION FOR THE CURRENT YEAR IDC$=IDC$+IDCG9$ IF RTIME NOT= (STARG9+6.) THEN GO TO 98 HERE IF PROJECT IS COMPLETED THIS YEAR AUGMENT REAL PLANT IN SERVICE FOR THIS CATEGORY (HYDRO) PH$76=PH$76+(456.7*A (1909)) AUGMENT HISTORIC DOLLAR PLANT IN SERVICE FOR THIS CATEGORY (HYDRO) PH$H=PH$H+IG9$*J1L*IG9$+J2L*IG9$+J3L*IG9$+ J4L*IG9$+J5L*IG9$+J6L*IG9$+IDCG9$+J1L*IDCG9$+ J2L*IDCG9$+J3L*IBCG9$+J4L*IDCG9$+J5L*IDCG9$+J6L*IDCG9$ AUGMENT CRITICAL ENERGY CAPABILITY FOR THIS CATEGORY (HYDRO) SEHCC=SEHCC+4773. . AUGMENT AVERAGE ENERGY CAPABILITY FOR THIS CATEGORY (HYDRO) SEHAC=SEHAC+5520. AUGMENT CAPACITY CAPABILITY FOR THIS CATEGORY (HYDRO) SCH=SCH+900. 173 98 IF A(2011) NOT= 0. THEN GO TO 100 IF ft (2010) NOT= 0. THEN GO TO 505 100 IF RTIME>{STARG10*6.) THEN GO TO 108 IF RTIM E= ST A RG10 THEN G10$76=. 1*A{1910) IF RTIME=(STARG10+1.) THEN G10$76=1.9*A{1910) IF RTIME=(STARG10+2.) THEN G10$76=2. 9*A (1 9 10) IF RTIME=(STARG10+3.) THEN G10$76=4.8*A{1910) IF RTIME=(STARG10+4.) THEN G10$76=7.9*A{1910) IF RTIME=(STARG10+5. ) THEN G10$76=4. 5*A (1 910) IF RTIME= (STARG 10+6. ) THEN G 10$76=0. *A (1 91 0) IGl0$=PEXOG/2.11*G10$76 IDCG10$=A (1872) * ( (.5*IG10$) +J 1L*IG10$+J2L*IG10$ + J3L*IG10$+J4L*IG10$+J5L*IG10$+J6L*IG10$) IDC$=IDC$+IDCG10$ IF RTIME NOT= (STARG10+5.) THEN GO TO 108 PH$76=PH$76+(22.1*A(1910)) PH$H=PH$il+IG1O$+JlL*IG10$+J2L*IG10$+J3L*IG10$ + J4L*IG10$+J5L*IG10$+J6L*IG10$+IDCG10$+J1L*IDCG10$+ J2L*IDCG10$+J3L*II3CG10$ + J4L*IDCG10$+J5L*IDCG10$+J6L*IDCG10$ SEHCC=SEHCC+1634. SEHAC=SEHAC+1890. SCH=SCH+450. 108 IF A{2011) NOT= 0. THEN GO TO 110 IF A (2010) NOT= 0. THEN GO TO 505 110 IF RTIME>(STARG11*4.) THEN GO TO 118 IF RTIME=STARG1 1 THEN G 11 $76= 1. 9*A { 191 1) IF RTIME=(STARG11+1.) THEN G11$76=2.9*A{1911) IF RTIME=(STARG11+2.) THEN G11$76=4.8*A (1911) IF RTIME= (STARG 11+3.) THEN G11 $7 6=7. 9*A { 19 11) IF RTIME=(STARG11+4.) THEN G11$76=4.5*A(1911) IG11$=PEX0G/2.11*G11$76 IDCG11$=A (1872) * ( (.5*IG11$) • J 1L*IG 11$+J2L*IG 11$+ J3L*IG11$+J4L*IG11$+J5L*IG11$+J6L*IG11$) IDC$=IDC$+IDCG11$ IF RTIME NOT= (STARG11*4.) THEN GO TO 118 PH$76=PH$76+(22.*A{1911) ) PH$H=PH$H+IG11$+J1L*IG11$•J2L*IG11$+J3L*IG11$+ J4L*IG11$+J5L*IG11$+J6L*IG11$*IDCG11$+J1L*IDCG11$+ J2L*IDCG11$ + J3L*IDCG11$*J4L*IDCG11$+J5L*IDCG11$ +J6L*IDCG11 $ SEHCC=SEHCC*484. SEHAC=SEHAC+560. SCH=SCH + 450. 118 IF A{2011) NOT= 0. THEN GO TO 180 IF A{2010) NOT= 0. THEN GO TO 505 120 IF RTIME<STARG12 THEN GO TO 128 IF RTIME>(STARG12+2.) THEN GO TO 128 IF RTIME=STARG12 THEN G12$76=2.*A{1912) IF RTIME= (STARG 12 + 1.) THEN G 12$7 6=5. *A (1 9 12) IF RTIME=(STARGl2+2.) THEN G12$76=3.1 *A{1912) IG12$=PEXOG/2.11*G12$76 IDCG12$=A{1872)*((.5*1612$)+J1L*IG12$+J2L*IG12$+ J3L*IG12$+J4L*IG12$+J5L*IG12$+J6L*IG12$) IDC$=IDC$+IDCG12$ IF RTIME NOT= <STARG12+2.) THEN GO TO 128 PH$76=PH$76 + (10. 1*A(1912) ) PH$H=PH$H+IG12$+J1L*IG12$+J2L*IG12$+J3L*IG12$+ J4L*IG12$+J5L*IG12$+J6L*IG12$+IDCG12$+J1L*IDCG12$+ J2L*IDCG12$+J3L*IDCG12$+J4L*IDCG12$+J5L*IDCG12$*J6L*IDCG12$ SEHCC=SEHCC+875. SEHAC=SEHAC+875. 174 SCH=SCH+0. 128 IF A (2011) NOT= 0. THEN GO TO 505 IF A(2010) NOT= 0. THEN GO TO 505 130 IF RTIHE<STAEG13 THEN GO TO 138 IF RTIME>(STARG13+3.) THEN GO TO 138 IF RTIME=STARG13 THEN G13$76=2.4*A{1913) IF RTIME=(STARG13+1.) THEN Gl3$76=5.3*A(19 13) IF RTIME=(STARG13+2.) THEN G13$76=6.*A (1913) IF RTIME= (STARG13+3.) THEN G13$76=2. 5*A (1913) IG13$=PEXOG/2.11*G13$76 IDCG13$=A (1872)*{{.5*IG13$)+J1L*IG13$+J2L*IG13$+ J3L*IG13$*J4L*IG13$*J5L*IG13$+J6L*IG13$) IDC$=IDC$+IDCG13$ IF RTIME NOT= (STARG13+3*) THEN GO TO 138 PH$76=PH$76+(16.2*A(1913) ) PH$H=PH$H*IG13$+J1L*IG13$+J2L*IG13$+J3L*IG13$+ J4L*IG13$+J5L*IG13$+J6L*IG13$+IDCG13$*J1L*IDCG13$+ J2L*IDCG13$+J3L*IDCG13$+J4L*IDCG13$+J5L*IDCG13$+J6L*IDCG13$ SEHCC=SEHCC+0. SEHAC=SEHAC+0. SCH=SCH + 275. 138 IF A(2011) NOT= 0. THEN GO TO 505 IF A (2010) NOT= 0. THEN GO TO 505 140 IF RTIME<STARG14 THEN GO TO 158 IF RTIME> (STARG 14+6.) THEN GO TO 158 IF RTIME=STARG14 THEN G14$76=1.9*A (1914) IF RTIME=(STARG14 + 1.) THEN G14$76=12.8*A {1914) IF RTIME= (STARG 14+2. ) THEN G 14$7 6=33. 8*A (1914) IF RTIME=(STARGl4+3.) THEN G14$76=42.5*A (1914) IF RTIME= (STARG 14 + 4.) THEN G1 4$76= 28. 4*A { 1 91 4) IF RTIME=(STARG14+5.) THEN G14 $76= 11. 9*A ( 19 1 4) IF RTIME=(STARG14+6.) THEN G14$76=2.1 *A{1914) IGl4$=PEX0G/2.11*G14$76 IDCG14$=A(1872) * ( (.5*IG14$) •J1L*IG14$+J2L*IG14$* J3L*IG14$+J4L*IG14$+J5L*IG14$+J6L*IG14$) IDC$=IDC$+IDCG14$ IF RTIME NOT= (STARG14+6.) THEN GO TO 158 PH$76=PH$76 + {133. 4*A (1914)) PH$H=PH$H*IG14$+J1L*IG14$*J2L*IG14$*J3L*IG14$* J4L*IG14$+J5L*IG14$+J6L*IG14$+IDCG14$+J1L*IDCG14$+ J2L*IDCG14$+33L*IDCG14$+J4L*IDCG14$+J5L*IDCG14$+J6L*IDCG14$ IF STARG21<=STAEG14 THEN GO TO 150 SEHCC=SEHCC+2750. SEHAC=SEHAC+3110. SCH=SCH+0. GO TO 158 150 SEHCC=SEHCC+3346. SEHAC=SEHAC+382 8. SCH=SCH+0. 158 IF A(2011) NOT= 0. THEN GO TO 505 IF A(2010) NOT= 0. THEN GO TO 505 160 IF RTIME<STARG16 THEN GO TO 168 IF RTIME>(STARG16+4.) THEN GO TO 168 IF RTIME=STARG16 THEN G16$76=1,*A{1916) IF RTIME=(STARG16 + 1.) THEN G16$76=2 . * A (1916) IF RTIME= (STARG 16 + 2.) THEN G16$7 6=3. *A (191 6) IF RTIME=(STARG16 + 3.) THEN G16$76=7.*A (1916) IF RTIME=(STARG16+4.) THEN G16$76=3,*A{1916) IG16$=PEXOG/2.11*G16$76 IDCG16$=A(1872) * ((.5*IG16$)+J1L*IG16$ + J2L*IG16$+ 175 J3L*IG16$+J4L*IG16$+J5L*IG16$+J6L*IG16$) IDC$=IDC$*IDCG16$ IF RTIME NOT= (STARG 16+4.) THEN GO TO 168 PH$76=PH$76+(16.*A(1916)) PH$H=PH$H+IG16$ + J1L*IG16$+J2I,*IG16$+J3L*IG16$* J4L*IG16$+J5L*IG16$+J6L*IG16$+IDCG16$+J1L*IDCG16$+ J2L*IDCG16$*J31*IDCG16$+J4L*IDCG16$+J51*IDCG16$+J6L*IDCG16$ SEHCC=SEHCC+0. SEHAC=SEHAC*0. SCH=SCH+400. 168 IF A(2011) NGT= 0. THEN GO TO 170 IF A (2010) NOT= 0. THEN GO TO 505 170 IF RTIME<STARG17 THEN GO TO 178 IF RTIME>(STARG17*4.) THEN GO TO 178 IF RTIME=STARG17 THEN G17$76=1.*A(1917) IF RTIME=(STARG17+1.) THEN G 17$76=2. *A {1917) IF RTIME=(STARG 17 + 2.) THEN G 17$76=3 . * A (1 917) IF RTIME=(STARG17+3. ) THEN G17$76=6.3*A(1917) IF RTIME=(STARG17+4.) THEN G17 $7 6=3. *A (1 917) IG17$=PEXOG/2.11*G17$76 IDCG17$=A(1872)*{{.5*IG17$)+J1L*IG17$+J2L*IG17$+ J3L*IG17$+J4L*IG17$+J5L*IG17$+J6L*IG17$) IDC$=IDC$+IDCG17$ IF RTIME NOT= (STARG17*4.) THEN GO TO 178 PH$76=PH$76+(15.3*A(1917)) PH$H=PH$H+IG17$+J1L*IG17$*J2L*IG17$*J3L*IG17$+ J4L*IG17$+J5L*IG17$*J6L*IG17$+IDCG17$+J1L*IDCG17$+ J2L*IDCG17$+J3L*IDCG17$+J4L*IDCG17$+J5L*IDCG17$+J6L*IDCG17$ SEHCC=SEHCC+0. SEHAC=SEHAC+0. SCH=SCH+400. 178 IF A (2011) NOT= 0. THEN GO TO 505 IF A(2010) NOT= 0. THEN GO TO 505 180 IF RTIME<STARG18 THEN GO TO 188 IF RTIME>(STARG18+4.) THEN GO TO 188 IF RTIME=STARG18 THEN G18$76=2.*A{1918) IF RTIME=(STARG18+1.) THEN G18$76=3.*A(1918) IF RTIME=(STARGl8+2. ) THEN G18$76=5.*A (1918) IF RTIME=(STARG18+3.) THEN G1 8$7 6= 8. *A { 1 91 8) IF RTIME= (STARG18 + 4.) THEN G18$76=6.9*A(1918) IG18$=PEXOG/2.11*G18$76 IDCG18$=A(1872)*{(.5*IG18$)*J1L*IG18$+J2L*IG18$+ J3L*IG18$+J4L*IGl8$+J5L*IGl8$+J6L*IGl8$) IDC$=IDC$+IDCG18$ IF RTIME NOT= (STARG 18+4.) THEN GO TO 188 PH$76=PH$76+(24.9*A(1918)) PH$H=PH$H+IG18$+J1L*IG18$+J2L*IG18$+J3L*IG18$+ J4L*IG18$+J5L*IG18$+J6L*IG18$+IDCG18$+J1L*IDCG18$+ J2L*IDCG18$+J3L*IDCG18$+J4L*IDCG18$+J5L*IDCG18$+J6L*IDCG18$ SEHCC=SEHCC+0. SEHAC=SEHAC+0. SCH=SCH*450. 188 IF A (2011) NOT= 0. THEN GO TO 190 IF A (2010) NOT= 0. THEN'GO TO 505 190 IF RTIME<STARG19 THEN GO TO 198 IF RTIHE>(STARG19+4.) THEN GO TO 198 IF RTIME=STARG19 THEN G19$76=2.*A(1919) IF RTIME=(STARG19+1.) THEN G19$76=3.*A{1919) IF RTIME=(STARGl9+2.) THEN G19$76=5.*A (1919) IF RTIME= {STARG19 +3.) THEN G19$76=8. *A (191 9) 176 IF RTIME= (STARG19+4.) THEN G 19$76=4.7*A{1919) IGl9$=PEX0G/2.11*G19$76 IDCG19$=A(1872)*({.5*IG19$) +J1L*IG19$*32L*IG19$+ J3L*IG19$+J4L*IG19$+J5L*IG19$+J6L*IG19$) IDC$=IDC$+IDCG19$ IF RTIME NOT= (STARG19+4.) THEN GO TO 198 PH$76=PH$76+{22.7*A(1919) ) PH$H=PH$H+IG19$+J1L*IG19$+J2L*IG19$+J3L*IG19$+ J4L*IG19$+J5L*IG19$+J6L*IG19$+IDCG19$+J1L*IDCG19$+ J2L*IDCG19$+J3L*IDCG19$+J4L*IDCG19$+J5L*IDCG19$+J6L*IDCG19$ SEHCC=SEHCC+0. SEHAC=SEHAC+0. SCH=SCH+450. 198 IF A{2011) NOT= 0. THEN GO TO 505 IF A(2010) NGT= 0. THEN GO TO 505 200 IF RTIME<STARG20 THEN GO TO 208 IF RTIME>{STARG20+4.) THEN GO TO 208 IF RTIME=STARG20 THEN G20$76=.7*A{1920) IF RTIME= (STARG20 + 1. ) THEN G20$76=1.1*A(1920) IF RTIME=(STARG20+2.) THEN G20$76=1.7*A{1920) IF RTIME=(STARG20+3.) THEN G20$76=5.4*A (1920) IF RTIME= {STARG20 + 4. ) THEN G20$76=5. 7*A { 1920) IG20$=PEXOG/2.11*G20$76 IDCG20$=A(1872)*((.5*IG20$)+J1L*IG20$+J2L*IG20$+ J3L*IG20$+J4L*IG20$+J5L*IG20$+J6L*IG20$) IDC$=IDC$+IDCG20$ IF RTIME NOT= {STARG20 + 4.) THEN GO TO 208 PH$76=PH$76*(14.6*&(192 0)) PH$H=PH$H+IG20$+J1L*IG20$+J2L*IG20$+J3L*IG20$+ J4L*IG20$+J5I*IG20$*J6L*IG20$+IDCG20$+J1L*IDCG20$+ J2I*IDCG20$+J3L*IDCG20$*J4L*IDCG20$+J5L*IDCG20$*J6L*IDCG20$ SEHCC=SEHCC+65. SEHAC=SEHAC+75. SCH=SCH+175. 208 IF A (2011) NOT= 0. THEN GO TO 505 IF A (2010) NOT= 0. THEN GO TO 505 210 IF STARG21=0. THEN GO TO 238 IF RTIME>(STARG21+6.) THEN GO TO 218 IF RTIME=STARG21 THEN G21$76=3.*A{1921) IF RTIME=(STARG21 + 1.) THEN G21$76=24.*A (1921) IF RTIME= {STARG21 + 2. ) THEN G21 $76=28. 5*A {1 92 1) IF RTIME={STARG21+3.) THEN G21$76=54.*A{1921) IF RTIME={STARG21+4.) THEN G21$76=98.*A{ 1921) IF RTIME=(STARG21+5.) THEN G21$76=111.*A(1921) IF RTIME= (STABG21 + 6.) THEN G21$76=17.*A (1921) IG21$=PEXOG/2.11*G21$76 IDCG21$=A{1872) * ( (.5*IG21$) + J1 L*IG21 $+J2L*IG21 $• J3L*IG21$+J4L*IG21$+J5L*IG21$+J6L*IG21$) IDC$=IDC$+IDCG21$ IF RTIME NOT= (STARG21+6.) THEN GO TO 218 PH$76=PH$76+ (335. 5*A (1921)) PH$H=PH$H+IG21$+J1L*IG21$+J2L*IG21$*J3L*IG21$• J4L*IG21$+J5L*IG21$+J6L*IG21$+IDCG21$+J1L*IDCG21$+ J2L*IDCG21$+J3L*IDCG21$+J4L*IDCG21$*J5L*IDCG21$+J6L*IDCG21$ SEHCC=SEHCC+2702. SEHAC=SEHAC+2600. SCH=SCH+450. 218 IF A {2011) NOT= 0. THEN GO TO 220 IF A (2010) NOT= 0. THEN GO TO 505 220 IF RTIME>(STARG22+4.) THEN GO TO 228 177 IF RTIME=STARG22 THEN G22$76=1.*A{1922) IF RTIME=(STARG22+1.) THEN G22$76= 1.6*A (1922) IF RTIHE= (STARG22+2.) THEN G22$76=2.9*A (1922) IF RTIME=(STARG22+3.) THEN G22$76=4.3*A(1922) IF RTIME=(STARG22 + 4. ) THEN G22$76=5.2*A ( 1922) IG22$=PEXOG/2.11*G22$76 IDCG22$=A(1872) *{ (.5*IG22$) •J1L*IG22$+J2L*IG22$+ J3L*IG2 2$*J4L*IG22$+J5L*IG22$+J6L*IG22$) IDC$=IDC$+IDCG22$ IF RTIME NOT= (STARG22*4.) THEN GO TO 228 PH$76=PH$76+(15.*A(1922)) PH$H=PH$H*IG22$+J1L*IG22$+J2L*IG22$*J3L*IG22$* J41*IG22$+J5L*IG22$+J6L*IG22$+IDCG22$+J1L*IDCG22$+ J2L*IDCG22$ + J3I.*IDCG22$*J4L*IDCG22$+J5L*II>CG22$+J6L*IDCG22$ SEHCC=SEHCC+1143. SEHAC=SEHAC+1100. SCH=SCH*225. 228 I F A (2011) NOT= 0. THEN GO TO 230 IF A(2010) NOT= 0. THEN GO TO 505 230 IF RTIHE>{STARG23*4.) THEN GO TO 238 IF RTIME=STARG23 THEN G23$76 = 1.*A (1923) IF RTIME=(STARG23*1.) THEN G23$76=1.6*A (1923) IF RTIME=(STARG23+2.) THEN G23$76=2.9*A{1923) IF RTIME=(STARG23+3.) THEN G23$76=4.3*A(1923) IF BTIME=(STARG23+4.) THEN G23$76=5.2*A{1923) IG23$=PEXOG/2.11*G23$76 IDCG23$=A{1872) *{ (.5*IG23$) +J 1L*IG23$+J2L*IG23$ + J3L*IG2 3$*J4L*IG23$*J5L*IG23$+J6L*IG23$) IDC$=IDC$+IDCG23$ IF RTIME NOT= (STARG23+4.) THEN GO TO 238 PH$76=PH$76+(15.*A{1923)) PH$H=PH$H+IG23$+J1L*IG23$+J2L*IG23$+J3L*IG23$+ J4L*IG23$+J5L*IG23$+J6L*IG23$+IDCG23$+J1L*IDCG23$+ J2L*IDCG23$+J3L*IDCG23$+J4L*IDGG23$+J51*IDCG23$*J6L*IDCG23$ SEHCC=SEBCC+613. SEHAC=SEHAC+590., SCH=SCH + 225. 238 IF A (2011) NOT= 0. THEN GO TO 505 IF A (2010) NOT= 0. THEN GO TO 505 240 IF STARG24=0. THEN GO TO 310 310 IF RTIME<STARG31 THEN GO TO 318 IF RTIME>(STARG31+1.) THEN GO TO 318 IF RTIME=STARG31 THEN G31$76=11.6*A(1931) IF RTIME= (STARG31 + 1.) THEN G31$76=10.*A(1931) IG31$=PEXOG/2.11*G31$76 IDCG31$=A{1872) * ((.5*IG31$) +J 1L*IG31$) IDC$=IDC$+IDCG31$ IF RTIME NOT= (STARG31+1.) THEN GO TO 318 PG$76=PG$76+(21.6*A (1931)) PG$H=PG$H+IG31$+J1L*IG31$+IDCG31$+JlL*IDCG31$ SEGAC=SEGAC+657. SCG=SCG+150. 318 IF A{2011) NOT= 0. THEN GO TO 320 IF A (2010) NOT= 0. THEN GO TO 505 320 IF RTIME<STARG32 THEN GO TO 328 IF RTIME>(STARG32+1.) THEN GO TO 328 IF RTIME=STARG32 THEN G32$76=11.6*A{1932) IF RTIME=(STARG32+1.) THEN G32$76=10.*A{1932) IG32$=PEXOG/2.11*G32$76 IDCG32$=A (1872) * ( (. 5*IG3 2$) +J 1L*IG32$) IDC$=IDC$*IDCG32$ IF RTIME NOT= (STARG32+1.) THEN GO TO 328 PG$76=PG$76+(21.6*A (193 2)) PG$H=PG$H+IG32$ + J1L*IG32$+IDCG32$«-J1L*IDCG32$ SEGAC=SEGAC+657. SCG=SCG+150. 328 IF A (2011) NOT= 0. THEN GO TO 505 IF A (2010) NOT= 0. THEN GO TO 505 33 0 IF RTIHE<STARG33 THEN GO TO 338 IF RTIME>{STARG33*1.) THEN GO TO 338 IF RTIME=STARG33 THEN G33$76= 11. 6*A{1933) IF RTIME=(STARG33+1.) THEN G33$76=10.*A(1933) IG33$=PEXOG/2.11*G33$76 IDCG33$=A (1872) * { {. 5*IG33$) +J 1L*IG33$) IDC$=IDC$+IDCG33$ IF RTIME NOT= (STARG33+1.) THEN GO TO 338 PG$76=PG$76+(21.6*A (193 3)) PG$H=PG$H+IG33$+J1L*IG3 3$*IDCG33$+J1L*IDCG33$ SEGAC=SEGAC+657. SCG=SCG+150. 338 IF A (2011) NOT= 0. THEN GO TO 505 IF A (2010) NOT= 0. THEN GO TO 505 340 IF RTIME<STARG34 THEN GO TO 348 IF RTIME>(STARG34+1.) THEN GO TO 348 IF RTIME=STARG34 THEN G34$76=23. 2*A{1934) IF RTIME=(STARG34+1.) THEN G34$76=20.*A{1934) IG34$=PEXOG/2.11*G34$76 IDCG34$=A<1872) * ((.5*IG34$) +J1L*IG34$) IDC$=IDC$+IDCG34$ IF RTIME NOT= (STARG34+1.) THEN GO TO 348 PG$76=PG$76+(43.2*A(1934)) PG$H=PG$H+IG34$+J1L*IG34$ +IDCG34 $+J1L*IDCG34$ SEGAC=SEGAC+1314. SCG=SCG+300. 348 IF A (2011) NOT= 0. THEN GO TO 505 IF A(2010) NOT= 0. THEN GO TO 505 350 I F RTIME<STARG35 THEN GO TO 358 IF RTIME>(STARG35+1.) THEN GO TO 358 IF RTIHE=STARG35 THEN G35$76=46.4*A(1935) IF RTIME=(STARG35*1.) THEN G35$76=40.*A(1935) IG35$=PEXOG/2.11*G35$76 IDCG35$=A (1872) * {(. 5*IG35$) +J 1L*IG35$) IDC$=IDC$*IDCG35$ IF RTIME NOT= (STARG35+1.) THEN GO TO 358 PG$76=PG$76+(86.4*A(1935)) PG$H=PG$H+IG35$+J1L*IG35$+IDCG35$+J1L*IDCG35$ SEGAC=SEGAC+2628. SCG=SCG+600. 358 IF A (2011) NOT= 0. THEN GO TO 505 IF A (2010) NOT= 0. THEN GO TO 505 360 IF RTIME>(STARG36+6.) THEN GO TO 368 IF RTIME<STARG36 THEN GO TO 505 IF RTIME=STARG36 THEN G36$76=1.*A{1936) IF RTIME=(STARG36+1.) THEN G36$76=5.*A (1936) IF RTIME=(STARG36 + 2.) THEN G36$76=20.* A(1936) IF RTIME=(STARG36+3.) THEN G36$76=40.*A{1936} IF RTIME=(STARG36 + 4.), THEN G36$76=50. *A (1936) IF RTIME=(STARG36+5.) THEN G36$76=59.*A(1936) IF RTIME=(STARG36+6.) THEN G36$76=25.*A{1936) IG36$=PEXOG/2.11*G36$76 179 IDCG36$=A{1872)*((.5*IG36$)+J1L*IG36$+J2L*IG36$+ J3L*IG36$+J4L*IG36$+J5L*IG36$+J6L*IG36$) IDC$=IDC$+IDCG36$ IF RTI8E NOT= (STARG36 + 6.) THEN GO TO 368 PC$76=PC$76+(200.*A(1936)) PC$H=PC$H+IG36$+J1L*IG36$+J2L*IG36$+J3L*IG36$+ J4L*IG36$+J5L*IG36$*J6L*IG36$+IDCG36$+J1L*IDCG36$+ J2L*IDCG36$+J3L*IDCG36$+jaL*IDCG36$+J5L*IDCG36$+J6I*IDCG36$ SECAC=SECAC+3420. SCC=SCC+500. 368 IF A (2011) NOT= 0. THEN GO TO 370 IF A(2010) NOT= 0. THEN GO TO 505 370 IF BTIME>(STARG37+5.) THEN GO TO 378 IF RTIS3E=STARG37 THEN G37$76=2.*A (1937) IF RTIHE=(STARG37+1.) THEN G37$76=13.*A(1937) IF BTIHE=(STARG37+2.) THEN G37$76=25.*A{1937) IF RTIME=(STARG37+3.) THEN G37$76=25.*A (1937) IF RTIME=(STARG37+4.) THEN 637$76=30.*A{1937) IF RTIME=(STARG37+5.) THEN G37$76=11.*A{1937) IG37$=PEXOG/2.11*G37$76 IDCG37$=A(1872) * ( (.5*1637$) +J 1L*IG37$+J2L*IG37$+ J3L*IG37$+J4L*IG37$+J5L*IG37$+J6L*IG37$) IDC$=IDC$+IDCG37$ IF RTIHE NOT= (STARG37+5.) THEN 60 TO 378 PC$76=PC$76+(106.*A(1937)) PC$H=PC$H+IG37$+J1L*IG37$+J2L*IG37$+J3L*IG37$+ J4L*IG37$+J5L*IG37$+J61*IG37$+IDCG37$*J1L*IDCG37$+ J2L*IDCG37$+J3L*IBCG37$+J4L*IDCG37$+J5L*IDCG37$+J61*IDCG37$ SECAC=SECAC+3420. SCC=SCC+5G0. 378 IF A (2011) NOT= 0. THEN GO TO 380 IF A(2010) NOT= 0. THEN GO TO 505 380 IF BTI!9E> (STAR038+5. ) THEN GO TO 388 IF R TIME=ST A RG 3 8 THEN G38$76=2.*A (1938) IF RTIHE=(STARG38+1.) THEN G38$76=13.*A(1938) IF RTIHE=(STARG38+2.) THEN 638$76=25.*A{1938) IF RTIHE=(STAR638+3.) THEN 638$76=25.* A(1938) IF BTIME= (STARG38+4.) THEN G38$76=30.* A{1938} IF BTIME=<STABG38*5.) THEN G38$76= 11. *A { 1938) IG38$=PEXOG/2.11*G38$76 IDCG38$=A(1872)*((.5*IG38$)+J1L*IG38$+J2L*IG38$+ J31*IG38$+341*IG38$+J5L*IG38$+J6L*IG38$) IDC$=IDC$+IDCG38$ IF BTIflE NOT= (STABG38+5.), THEN GO TO 388 PC$76=PC$76+(106.*A(1938)) PC$H=PC$H*IG38$+J1L*IG38$+J2L*IG38$+J3L*IG38$+ J4L*IG3 8$+J51*IG38$+J6L*IG38$+IDCG38$+J1L*IDCG38$+ J2L*IDCG38$+J3L*IDCG38$+J4L*IDCG38$+J5I*IDCG38$+J6L*IDCG38$ SECAC=SECAC+3420. SCC=SCC+500. 388 IF A (2011) NOT= 0. THEN GO TO 390 IF A(2010) NOT= 0. THEN GO TO 505 390 IF BTIME>(STABG39+5.) THEN GO TO 398 IF RTIME=STARG39 THEN G39$76=2.*A(1939) IF RTIHE=(STARG39+1.} THEN G39$76=13.*A(1939) IF RTIME=(STARG39+2.) THEN 639$76=25.*A{1939) IF RTIME=(STARG39+3.) THEN G39$76=25.*A (1939) IF RTIME=(STABG39+4.) THIN G39$76=30.*A{1939) IF RTIHE=(STARG39+5.)THEN G39$76=11.*A{1939) IG39$=PEXOG/2.11*G39$76 180 IDCG39$=A (1872) *{ (.5*IG39$) +J1L*IG39$+J2L*IG39$+ J3L*IG39$+J4L*IG39$+J5L*IG39$+J6L*IG39$) IDC$=IDC$+IDCG39$ IF RTIME NOT= (STARG39+5.) THEN GO TO 398 PC$76=PC$76*(106.*A(1939)) PC$H=PC$H*IG39$+J1L*IG39$+J2L*IG39$+J3L*IG39$+ J4L*IG3 9$+J5L*IG39$+J6L*IG39$*IDCG39$*J1L*IDCG39$+ J2L*IDCG39$+J3L*IDCG39$+J4L*IDCG39$+J5L*IDCG39$+J6L*IDCG39$ SECAC=SECAC*3420. SCC=SCC+500. 398 IF A{2011) NOT= 0. THEN GO TO 505 IF A(2010) NOT= 0. THEN GO TO 505 400 IF RTIME>(STARG40+6.) THEN GO TO 408 IF RTIME=STARG40 THEN G 4 0$76=5.*A(1940) IF RTIME=(STARG40+1.) THEN G40$76=15.*A (1940) IF RTIME= (STARG40+2.) THEN G40$76=30.*A(1940} IF RTIME= (STARG40+3.) THEN G40$76=40.*A (1940) IF RTIME=(STARG40+4.) THEN G40$76=45.* A(19 40} IF RTIME= (STARG40+5.) THEN G40$76=50.*A{1940) IF RTIHE=(STARG40+6.) THEN G40$76=15.*A (1940) IG40$=PEXOG/2.11*G40$76 IDCG40$=A (1872) * ( (.5*IG40$) * J1 L*IG40$+J2L*IG40 $+ J3L*IG40$+J4L*IG40$+J5L*IG40$+J6L*IG40$) IDC$=IDC$+IDCG4 0$ IF RTIME NOT= (STARG40+6.) THEN GO TO 408 PC$76=PC$76+(200.*A(1940)) PC$H=PC$H+IG40$+J1L*IG4 0$+,J21*IG40$+J3L*IG40$+ a4L*IG40$*J5L*IG40$+J6L*IG40$+IDCG40$+J1L*IDCG40$+ J2L*IDCG40$+J3L*IDeG40$+J4L*IDCG40$+J5L*IDCG4 0$+J6L*IDCG40$ SECAC=SECAC+4790. SCG=SCC+700. 408 IF A(2011) NOT= 0. THEN GO TO 410 IF A (2010) NGT= 0. THEN GO TO 505 410 IF RTIME>(STARG41+5.) THEN GO TO 418 IF RTIME=STARG41 THEN G41$76=7.*A{1941) IF RTIME= (STARG41*1.) THEN G41$76=20.*A(1941) IF RTIME=(STARG41+2.) THEN G41$76=30.*A (1941) IF RTIME= (STAEG41 + 3.) THEN G41$76=35.*A(1941) IF RTIME=(STARG41 + 4.) THEN G41$76=50.*A (1941) IF RTIME=(STAEG41 + 5.) THEN G41$76=15.*A {1941) IG41$=PEXOG/2.11*G41$76 IDCG41$=A (1872)* ( (.5*IG41$)+J1L*IG41$+J2L*IG41$ + J3L*IG41$+J4L*IG41$+J5L*IG41$+J6L*IG41$) IDC$=IDC$+IDCG41$ I F RTIME NOT= (STARG41+5.) THEN GO TO 418 PC$76=PC$76+(157.*A{ 1941)) PC$H=PC$H+IG41$*J1L*IG41$+J2L*IG41$*J3L*IG41$+ J4L*IG41$+J5L*IG41$+J6L*IG41$+IDCG41$+J1L*IDCG41$+ J21*IDCG41$+J3L*IDCG41$+J4L*IDCG41$+J5L*IDCG41$+J6L*IDCG41$ SECAC=SECAC+4790. SCC=SCC+700. 418 IF A(2011) NOT= 0. THEN GO TO 420 IF A{2010) NOT= 0. THEN GO TO 505 420 IF RTIME>(STARG42+5.) THEN GO TO 428 IF RTIME=STARG42 THEN G42$76=7.*A{1942) IF RTIME=(STARG42*1.) THEN G42$76=20.*A{1942) IF RTIME=(STARG42+2.) THEN G42$76=30.*A (1942) IF RTIHE=(STARG42+3.) THEN G42$76=35.*A{1942) IF RTIME=(STARG42+4.) THEN G42$76=50.*A(1942) IF RTIME={STARG42+5.) THEN G42$76=15.*A (1942) 181 IG42$=PEX0G/2.11*G42$76 IDCG42$=A (1872)* ( (-5*IG42$)+J1L*IG42$+J2L*IG42$+ J3L*IG42$+J4L*IG4 2$+J5L*IG42$+J6L*IG42$) IDC$=IDC$+IDCG42$ IF RTIME NOT= (STARG42*5.) THEN GO TO 428 PC$76=PC$76+(157.*A(1942)) PC$H=PC$H+IG42$+J1L*IG4 2$+J2L*IG42$+J3L*IG42$*- J4L*IG4 2$+J5I*IG42$+J6L*IG42$+IDCG42$+J1L*IDCG42$+ J2L*IDCG4 2$ + J3L*II)CG42$*J4L*IDCG42$+J5L*IDCG42$+J6I,*IDCG42$ SECAOSECAC + 4790. SCC=SCC+700. 428 IF A{2011) NOT= 0. THEN GO TO 430 IF A (2010) NOT= 0. THEN GO TO 505 430 IF RTIME>(STAEG43+5.) THEN GO TO 438 IF RTIME=STARG43 THEN G43$76=7.*A(1943) IF RTIME=(STARG43+1.) THEN G43$76=20.*A(1943) IF RTIME=(STARG43+2.) THEN G43$76=30.*A (1943) IF RTIME={STARG43 + 3.) THEN G43$76=35.*A {1943) IF RTIME=(STAEG43+4.) THEN G43$76=50.*A{1943) IF RTIME=(STARG43+5.) THEN G43$76=15.*A(1943) IG43$=PEXOG/2.11*G43$76 IDCG43$=A(1872) *{ (.5*IG43$)+J1L*IG43$+J2L*IG43$+ J3L*IG4 3$+J4L*IG43$+J5L*IG43$+J6L*IG43$) IDC$=IDC$+IDCG43$ IF RTIME NOT= (STARG43+5.) THEN GO TO 438 PC$7 6=PC$76 + {157.*A (1943)) PC$H=PC$H+IG43$ + J1L*IG43$+J2L*IG43$*J3:L*IG43$ + J4L*IG43$+J51*IG43$+J6L*IG43$+IDCG43$+J1L*IDCG43$+ J2L*IDCG4 3$>J3L*IDCG43$*J4L*IDCG4 3$+J5L*IDCG4 3$+J6L*IDCG43$ SECAC=SECAC+4790. SCC=SCC+700. 438 IF A(2011) NOT= 0. THEN GO TO 505 IF A (2010) NOT= 0. THEN GO TO 505 440 IF RTIME<STARG46 THEN GO TO 460 IF RTIME>(STARG46+6.) THEN GO TO 448 IF RTIME=STARG46 THEN G44$76=3.*A{1944) IF RTIME=(STARG46 + 1.) THEN G44$76=8. *A (1944) IF RTIME= (STARG46 + 2.) THEN G 44$76= 19 . * A { 19 44) IF RTIME=(STARG46+3.) THEN G44$76=35.*A(1944) IF RTIME=(STARG46+4.) THEN G44$76=45.*A{1944) IF RTIME=(STARG46+5.) THEN G44$76=45.*A(1944) IF RTIME=(STARG46+6.), THEN G44$76=45 . * A (1 944 ) IG44$=PEXOG/2.11*G44$76 IDCG44$=A (1872) *{ (.5*1644$) + J1L*IG44$+J2L*IG44 $+ J3L*IG4 4$+J4L*IG44$+J5L*IG44$+J6L*IG44$) IDC$=IDC$*IDCG4 4$ I F RTIME N0T= (STARG46+6.) THEN GO TO 44 8 PC$76=PC$76* (200.*A (1944) ) PC$H=PC$H+IG44$+J1L*IG44$+J2I*IG44$*J3L*IG44$+ J4L*IG4 4$+J5L*IG44$+J6L*IG44$+IDCG44$+J1L*IDCG44$+ J2L*IDCG44$+J3I*IDCG44$+J4L*IDCG44$+J5L*IDCG44$+J6L*IDCG44$ SEKAC=SEKAC+4790. SCK=SCK+700. 448 IF A(2011) NOT= 0. THEN GO TO 450 IF A{2010) NOT= 0. THEN GO TO 505 450 IF HTIME<STARG45 THEN GO TO 458 IF RTIME>(STARG45+6.) THEN GO TO 458 IF RTIME=STARG45 THEN G45$76=2.*A {1945) IF RTIME= (STARG45 + 1. ) THEN G45$76=5.*A (1 945) IF RTIME=(STARG45+2.) THEM G45$76= 10.*A{1945) 182 IF RTIME=(STARG45*3.) THEN G45$76=15.*A(1945) IF RTIME=(STARG45+4.) THEN G45$76=25.*A (1945) IF RTIME=(STARG45 + 5.) THEN G45$76=30.*A{1945) IF ETIME=(STARG 45+6.) THEN G45$76=40.*A(1945) IG45$=PEXOG/2.11*G45$76 IDCG45$=A (1872) *({.5*IG45$) +J1L*IG45$+J2L*IG45$* J3L*IG4 5$+J4L*IG45$+J5L*IG45$+J6L*IG45$) IDC$=IDC$+IDCG45$ IF RTIME NOT= (STARG45+6.) THEN GO TO 458 PC$76=PC$76+ (127.*A(1945)) PC$H=PC$H+IG45$+J1L*IG45$+J2L*IG45$+J3L*IG45$+ J4L*IG45$+J5L*IG45$+J6L*IG45$+IDCG45$+J1L*IDCG45$+ J2L*IDCG45$*J3L*IDCG45$+J4L*IDCG45$+J5L*IDCG4 5$+J6L*IDCG45$ SEKAC=SEKAC+479 0. SCK=SCK+700. 458 IF A (2011) NOT= 0. THEN GO TO 505 I F A (2010) NOT= 0. THEN GO TO 505 460 IF RTIME<STARG46 THEN GO TO 468 IF RTIME>(STARG46+6.) THEN GO TO 468 IF RTIME=STARG46 THEN G46$76=2.*A{1946) IF RTIME=(STARG46+1.) THEN G46$76=5 . *A (1 946) IF RTIME=(STARG46+2.) THEN G46$76=10.*A{1946) IF RTIME=(STARG46+3.) THEN G46$76=15.* A(1946) IF RTIME=(STARG46+4.) THEN G46$76=25.*A{1946) IF RTIME=(STARG46*5.) THEN G46$76=30.*A{1946) IF RTIME=(STARG46+6.) THEN G46$76=40.*A (1946) IG46$=PEXOG/2.11*G46$76 IDCG46$=A (1872) *{{.5*IG46$) *J1L*IG46$+J2L*IG46$• J3L*IG46$*-J4L*IG46$+J5L*IG46$+J6L*IG46$) IDC$=IDC$+IDCG46$ IF RTIHE NOT= (STARG46+6.) THEN GO TO 468 PC$76=PC$76+(127.*A(1946)) PC$H=PC$H*IG46$+J1L*IG46$+J2L*IG46$+J3L*IG46$+ J4L*IG46$+J5L*IG46$+J6L*IG46$+IDCG46$+J1L*IDCG46$+ J2L*IDCG46$+J3L*IDCG46$+J4L*IDCG46$+J5L*IDCG4 6$+J6L*IDCG46$ SEKAC=SEKAC+4790. SCK=SCK+700. 468 IF - A (2011) NOT= 0. THEN GO TO 505 IF A (2010) NOT= 0. THEN GO TO 505 470 IF STARG47=0. THEN GO TO 505 THE FOLLOWING SECTION AGGREGATES THE KEY FINANCIAL AND ENGINEERING VARIABLES FOR ALL THE GENERATION PROJECTS IGEN$76 - INVESTMENT IN GENERATION PROJECTS ($76) 505 IGEN$76=G1$76*G2$76+G3$76+G4$76+G5$76+G6$76*G7$76*G8$76*G9$76+ G10$76+G11$76*G12$76+G13$76+G14$76+G15$76+G16$76+G17$76+G18$76 G19$76+G20$76+G21$76*G22$76+G23$76+G24$76+G25$76+G26$76+G27$76 G28$76+G29$76+G30$76+G31$76+G32$76+G33$76+G34$76+G35$7 6+G36$76 G37$76+G38$76+G39$76+G40$76+G41$76+G42$76+G43$76+G44$76+G4 5$76 G46$7 6+G47$76+G48$76+G49$76*G50$76 IGEN$ - INVESTMENT IN GENERATION PROJECTS IGEN$=PEXOG/2.11*IGEN$76 SENHCC1 - ENERGY GENERATION CAPACITY FROM HYDRO-ELECTRIC SOURCES DURING CRITICAL RAINFALL PERIOD AT END OF EACH YEAR IF RTIME=75. THEN SENHCC1=19903. IF RTIME>=76. THEN SENHCC1=J1L*SENHCC1+SEHCC SENERHCC - AVERAGE ENERGY GENERATION CAPACITY FROM HYDRO 183 SOURCES DURING CRITICAL RAINFALL PERIOD IF RTIME=75. THEN S ENERHCC=19903. IF RTIME>=76. THEN SENERHCC=J1L*SENHCC1*{.5*SEHCC) SENHAC1 - ENERGY GENERATION CAPACITY FROM HYDRO-ELECTRIC SOURCES DURING AVERAGE RAINFALL PERIOD AT END OF EACH YEAR IF RTIME=75. THEN SENHAC1=21800. IF RTIME>=76. THEN SENHAC1=J1L*SENHAC1+SEHAC SENERHAC - AVERAGE ENERGY GENERATION CAPACITY FROM HYRDO- ELECTRIC SOURCES DURING AVERAGE RAINFALL PERIOD IF RTIME=75. THEN SENERHAC=21800. IF RTIME>=76. THEN SENERHAC=J1L*SENHAC1•(.5*SEHAC) SENGAC1 — ENERGY GENERATION CAPACITY FROM GAS TURBINES AT YEAR END IF RTIME=75. THEN J1L*SENGAC1=1476. IF RTIME>=75. THEN SENGAC 1=J1L*SENGAC1+SEGAC SENERGAC - AVERAGE ENERGY GENERATION CAPACITY FROM GAS TURBINES SENERGAC=J1L*SENGAC1+{.5*SEGAC) SENCAC1 - ENERGY GENERATION CAPACITY FROM HAT CREEK AT YEAR END SENCAC1=J1L*SENCAC1+SECAC SENERCAC - AVERAGE ENERGY GENERATION CAPACITY FROM HAT CREEK SENERCAC=J1L*SENCACH-{. 5*SECAC) SENKAC1 - ENERGY GENERATION CAPACITY FROM EAST KOOTENAY COAL AT YEAR END SENKAC1=J1L*SENKAC1+SEKAC SENERKAC=J1L*SENKAC1+(.5*SEKAC) SCAP_*S - VARIOUS CATEGORIES OF ENERGY CAPACITY CAPABILITY IF RTIME=75. THEN SCAPH=4186. IF RTIME>75. THEN SCAPH=31L*SCAPH+SCH SCAPB=900. IF RTIME=75. THEN SCAPG=327. IF RTIME>75. THEN SCAPG=J1L*SCAPG+SCG SCAPC=J1L*SCAPC+SCC SCAPK=J1L*SCAPK+SCK KPIS_$76 ,S - VARIOUS CATEGORIES OF POST-74 GENERATION PLANT IN SERVICE AT YEAR END ($76) KPISH$76=J1L*KPISH$76+PH$76 KPISG$76=J1L*KPISG$76*PG$76 KPISC$76=J1L*KPISC$76*-PC$76 KPISK$76=J1L*KPISK$76*PK$76 KPIS_$H - VARIOUS CATEGORIES OF POST-74 GENERATION PLANT IN SERVICE KPISH$H=J1L*KPISH$H+PH$H KPISG$H=J1L*KPISG$H+PG$H KPISC$H=J1L*KPISC$H+PC$H IF A (2011)=0. THEN GO TO 508 IF A(2011)=1. THEN GO TO 590 IF A{2011)=6. THEN GO TO 580 IF A(2011)=7. THEN GO TO 710 IF A(2011)=8. THEN GO TO 560 IF A{2011) = 11. THEN GO TO 810 184 IF A(2011) = 16. THEN GO TO 860 IF A(2011) = 17. THEN GO TO 900 IF A (2011) =21. THEN GO TO 940 IF A (2011) NOT= 0. THEN GO TO 1010 508 IF A{2010) NOT= 0. THEN GO TO 1010 CALCULATE FINANCIAL AND ENGINEERING INFORMATION FROM KNOWLEDGE ABOUT STARTING DATE OF EACH MAJOR ASSOCIATED TRANSMISSION PROJECT. CALCULATIONS PARALLEL THOSE FOR GENERATION PROJECTS (SEE STATEMENT 90) 510 IF RTIME>START1 THEN GO TO 520 IF RTIME=START1 THEN T1$76=13.8*A(1951) IT1$=PEXOG/2.11*T1$76 IDCT1$=5. IDC$=IDC$+IDCT1$ 52 0 IF RTIME>START2 THEN GO TO 530 IF RTIME=START2 THEN T2$76=11.4*A (1952) IT2$=PEXOG/2.11*T2$76 IF RTIME=(START2-1.) THEN IDCT2$=1.5 IF RTIME=START2 THEN IDCT2$=3.5 IDC$=IDC$*IDCT2$ IF RTIME NOT= START2 THEN GO TO 530 PT$76=PT$76+(20.6*A{1952)) PT$H=PT$H+30.9 530 I F RTIME>(START3•1.) THEN GO TO 540 IF RTIME=START3 THEN T3$76=42.*A (1953) IF RT IM E= ( ST A RT 3 + 1. ) THEN T3$76=46. 5*A (1 953) IT3$=PEXOG/2.11*T3$76 IF RTIME=START3 THEN IDCT3$=3.0 IF RTIME=(START3+1.) THEN IDCT3$=5.0 IDC$=IDC$*IDCT3$ IF RTIME NOT= (START3+1.) THEN GO TO 540 PT$76=PT$76*(85.*A(1953) ) PT$H=PT$H+117. 540 IF RTIME>(START4+1.) THEN GO TO 560 IF RTIME=START4 THEN T4$76=15.2*A {1954) IT4$=PEXOG/2.11*T4$76 IF RTIME=(START4-3.) THEN IDCT4$=.5 IF RTIME=(START4-2.) THEN IDCT4$=1. IF RTIME=(START4-1.) THEN IDCT4$ = 1.5 IF RTIME=STAST4 THEN IDCT4$=3. IDC$=IDC$+IDCT4$ IF RTIME NOT= START4 THEN GO TO 560 PT$76=PT$76+ (85. * A (1954).) PT$H=PT$H+117. 560 IF RTIME>(START6+4.) THEN GO TO 578 IF RTIME=START6 THEN T6$76=3.*A( 1956) IF RTIME= (START6+1.) THEN T6$76=3.6*A{1956) IF RTIME=(START6 + 2.) THEN T6$76=14.2*A (1956) IF RTIME= (START6»-3.) THEN T6$76= 16. 8*A (1956) IF RTIME=(START6 + 4.) THEN T6$76=8.9*A (1956) IT6$=PEXOG/2.11*T6$76 IDCT6$=A (1872)* { (.5*IT6$) + J 1L*IT6$+J2L*IT6$+ J3L*IT6$*J4L*IT6$+J5L*IT6$+J6L*IT6$) IDC$=IDC$+IDCT6$ IF RTIME NOT= (START6+4.) THEN GO TO 578 PT$76=PT$76+(46.5*A(1956) ) PT$H=PT$H+IT6$+J1L*IT6$+J2L*IT6$*J3L*IT6$+ 185 J4L*IT6$+J5I*IT6$+J6L*IT6$+IDCT6$+J1L*IDCT6$+ J2L*IDCT6$+J3L*IDCT6$*J4L*IDCT6$+J5L*IDCT6$+J6L*IDCT6$ 578 IF a (2011) NOT= 0. THEN GO TO 1005 580 IF RTIME>(START8+5.) THEN GO TO 588 IF RTIME=START8 THEN T8$76=2. 2*A (1 958) IF RTIME= (START8+ 1.) THEN T8$76=8. *A (1 958) IF RTIME=(START8+2.} THEN T8$76=4.3*A{1958) IF RTIME= (START8 + 3.)., THEN T8$76=16. 9*A (1 958) IF RTIME= (START8+4.) THEN T8$76=34 . 9*A (1 958) IF RTIME={START8 + 5.) THEN T8$76= 16. 1*A (1 958) IT8$=PEXOG/2.11*T8$76 IDCT8$=A{1872)*{(.5*IT8$)+J1I*IT8$+J2L*IT8$+ J3L*IT8$+J4L*IT8$+J51*IT8$ + J6L*IT8$) IDC$=IDC$+IDCT8$ IF RTIME NOT= (START 8+5.) THEN GO TO 588 PT$76=PT$76+(82.4*A(1958)) PT$H=PT$H+IT8$+J1L*IT8$+J2L*IT8$+J3L*IT8$+ J4L*IT8$+J5L*IT8$+J6I*IT8$+IDCT8$+J1L*IDCT8$+ J2L*IDCT8$+J3L*IDCT8$+J4L*IDCT8$+J5L*IDCT8$*J6L*IDCT8$ 588 IF A(2011) NOT= 0. THEN GO TO 1005 590 IF RTIME>(START9+6.) THEN GO TO 600 IF RTIME=START9 THEN T9$76=7.*A{1959) IF RTIME= (START9+1.) THEN T9$76=4.1*A(1959) IF RTIME=(START9+2.) THEN T9$76=1.2*A (1959) IF RTIME= (START9 + 3.) THEN T9$76=.7*A (1959) IF RTIME={START9+ 4.) THEN T9$76=2.8*A (1959) IF RTIME=(START9+5.) THEN T9$76=5.7*A ( 1959) IF RTIME= (START9 + 6.) THEN T9$76=1.8*A{ 1959) IT9$=PEXOG/2.11*T9$76 IDCT9$=A{1872)* ( (.5*IT9$) +J 1L*IT9$+J2L*IT9$+ J3L*IT9$+J4L*IT9$+J5I*IT9$+J6L*IT9$) IDC$=IDC$+IDCT9$ IF RTIME NOT= (START9+6.) THEN GO TO 600 PT$76=PT$76+(23.3*A(1959)) PT$H=PT$H+IT9$+J1I*IT9$+J2L*IT9$+J3L*IT9$+ J4L*IT9$+J5L*IT9$+J6L*IT9$*IDCT9$+J1L*IDCT9$+ J2L*IDCT9$+J3L*IDCT9$+J4L*IDCT9$+J5L*IDCT9$+J6L*IDCT9$ 600 IF RTIME> (START 10 + 5.) THEN GO TO 708 IF RTIME=STAHT10 THEN T10$76=1.*A{1960) IF RTIME= (START10 + 1.) THEN T10$76= 1.*a (1 960) IF RTIME=(START 10*2.) THEN T10$76=3.*A (1960) IF RTIME=(START 10 + 3.) THEN T10$76=5.5*A (1960) IF RTIME= (START 10+4.) THEN T 10$76=6. 7*A (1960) IF RTIME=(START10+5.) THEN T10$76=2.8*A(1960) IT10$=PEXOG/2.11*T10$76 IDCT10$=A{1872)*{(.5*IT10$)+J1L*IT10$+J2I*IT10$+ J3L*IT10$+J4L*IT10$+J5L*IT10$+J6L*IT10$) IDC$=IDC$+IDCT10$ IF RTIME NOT= (START 10+5.) THEN GO TO 708 PT$76=PT$76+(20.*A{1960)) PT$H=PT$H+IT10$+J1L*IT10$+J2L*rTlO$+J3L*ITlO$* J4L*IT10$+J5L*IT10$+J6L*IT10$+IDCT10$+J1L*IDCT10$+ J2L*IDCT10$+J3L*IECT10$*J4L*IDCT10$+J5L*IDCT10$+J6L*IDCT10$ 708 IF A{2011) NOT= 0. THEN GO TO 1005 710 IF START21=0. THEN GO TO 808 IF RTIME>(START21+4.} THEN GO TO 808 IF RTIME=STaRT2 1 THEN T2 1$76=4. 9*A { 1 97 1) IF RTIME= (START21 * 1.) THEN T21$76=5.9*A(1971) IF RTIME=(START21+2.} THEN T21$76=23.2*A (1971) IF RTIME=(ST1RT21+3.) THEN T21$76=27.4*A (1 97 1) 186 IF RTIME=(START21 +4 . ) THEN T2 1 $76= 14. 6*A (1 97 1) IT21$=PEX0G/2.11*T21$76 IDCT21$=A (1872) * ( (.5*IT21$) +«J TL*IT21$+J2L*IT21 $* J3L*IT21$+J4L*IT21$*J5L*IT21$+J6L*IT21 $) IDC$=IDC$+IDCT21$ IF RTIME NOT= (START21 + 4.) THEN GO TO 808 PT$76=PT$76+(76.*A(1971) ) PT$H=PT$H+IT21$+J1L*IT21$+J2L*IT21$+J3L*IT21$+ J4L*IT21$+J5L*IT21$*-J6L*IT21$+IDCT21$+J1L*IDCT21$»- J2L*IDCT21$+J3L*IDCT21$+J4L*IDCT21$+J5L*IDCT21$+J6L*IDCT21$ 808 IF A (2011) NOT= 0. THEN GO TO 1005 810 IF RTIME>(START31+2.) THEN GO TO 858 IF RTIME=START31 THEN T31$76=.3*A (1981) IF RTIME= (START31 * 1 . ) THEN T31$76=1.8*A ( 1981) I F BTIME= (START3 1+2. ) THEN T31 $76=. 9*A (1981) IT31$=PEXOG/2.11*T31$76 IDCT31$=A{1872)*{(,5*IT31$)*J1L*IT31$+J2L*IT31$+ J3L*IT31$+J4L*IT31$+J5L*IT31$+J6L*IT31$) IDC$=IDC$*IDCT31$ IF RTIHE NOT= (START31+2.) THEN GO TO 85 8 PT$76=PT$76+(3.*A (19 81) ) PT$H=PT$H+IT31$+J1I*IT31$+32L*IT31$+J3L*IT31$* J4L*IT31$+J5L*IT31$+J6L*IT31$+IDCT31$+J1L*IDCT31$+ J2L*IDCT31$*J3L*IDCT31$+J4L*IDCT31$*J5I*IDCT31$+J6L*IDCT31$ 858 IF A(2011) NOT= 0. THEN GO TO 1005 860 IF RTIME<START36 THEN GO TO 1005 IF RTIME>(START36+6.) THEN GO TO 880 IF RTIME=START36 THEN T36$76=2.3*A{1986) IF RTIME=(START36*1.), THEN T36$76=2. 6*A{ 1986) IF RTIME=(START36+2.) THEN T36$76=.7*A (1986) IF RTIME=(START36+3.) THEN T36$76=8.5*A(1986) IF RTIME=(START36+4.) THEN T36$76=16.7*A(1986) IF RTIHE=(START36+5.) THEN T36$76=5.8*A(1986) IF RTIHE= (START36 + 6.) THEN T36$76=4.2*A(1986) IT36$=PEXOG/2.11*T36$76 IDCT36$=A(1872)*((.5*IT36$)+J1L*IT36$+J2L*IT36$+ J3L*IT3 6$+J41*IT36$+J5L*IT36$+J6L*IT36$) IDC$=IDC$+IDCT36$ IF RTIME NOT= (START36+6.) THEN GO TO 880 PT$76=PT$76*(40.8*A(1986)) PT$H=PT$H+IT36$+J1L*IT36$+J2L*IT36$+J3L*IT36$+ J4L*IT36$+J5L*IT36$+J6L*IT36$*IDCT36$+J1L*IDCT36$+ J2L*IDCT36$+J3L*IDCT36$+J4L*IDCT36$+J5L*IDCT36$+J6L*IDCT36$ 880 IF RTIME> (START38+5.) THEN GO TO 898 IF RTIME=START38 THEN T38$76=.4*A (1988) IF RTIME=(START38+1.) THEN T38$76=1.5*A{1988) IF RTIME=(START38+2.) THEN T38$76=.8*A(1988) IF RTIME= (START38+3. ) THEN T38$76=3. 1 * A (1 988) IF RTIME=(START38 + 4.) THEN T38$76= 6. 4*A{ 1988) IF RTIME=(START38+5.) THEN T38$76=2.9*A(1988) IT38$=PEXOG/2.11*T38$76 IDCT38$=A(1872)*((.5*IT38$)+J1L*IT38$+J2L*IT38$* J3L*IT3 8$+J4L*IT38$+J5L*IT38$+J6L*IT38$) IDC$=IDC$+IDCT38$ IF RTIME NOT= (START38*5.) THEN GO TO 898 PT$76=PT$76+(15.1*A(1988)) PT$H=PT$H+IT38$+J1L*IT3 8$+J2L*IT38$+J3L*IT38$+ J41*IT38$+J5L*IT38$+J6L*IT38$+IDCT38$+J1L*IDCT38$* a2L*IDCT38$+J3L*IDCT38$+J4L*IDCT38$+J5I*IDCT38$+J6L*IDCT38$ 898 IF A(2011) NOT= 0. THEN GG TO 1005 187 900 IF RTIME>(START40+6. ) THEN GO TO 938 IF RTIME<START40 THEN GO TO 1005 IF RTIME=START40 THEN T40$76=1.*A { 1990) IF RTIME= (START40 + 1.) THEN T40$76=.8*A (1990) IF RTIME=(START40+2.) THEN T40$76=1. 4*A (1990) IF RTIME=(START40+3.) THEN T40$76=2.7*A (1990) IF RTIME= (START40+4.) THEN T40$76=3. 7*A (1990) IF RTIME=(START40+5.) THEN T40$76=6.9*A{1990) IF RTIME=(START40+6.) THEN T40$76=7.3*A{1990) IT40$=PEXOG/2.11*T40$76 IDCT40$=A (1872) *{ (.5*IT40$)+J1L*IT40$+J2L*IT40$+ J3L*IT40$+J4L*IT40$+J5L*IT40$+J6L*IT40$) IDC$=IDC$+IDCT4 0$ IF RTIME NOT= (START40+6.) THEN GO TO 938 PT$76=PT$76+(23.8*A(1990)) PT$H=PT$H*IT40$+J1L*IT4Q$+J2L*IT40$+J3L*IT40$+ J4L*IT40$+J5L*IT40$+J6L*IT40$+IDCT40$+J1L*IDCT40$+ J2L*IDCT40$+J3L*IDCT40$+J4L*IDCT40$+J5L*IDCT4 0$+J6L*IDCT40$ 938 IF A(2011) NOT= 0. THEN GO TO 1005 940 IF RTIME>(START44+6.) THEN GO TO 950 IF RTIME<START44 THEN GO TO 1005 IF RTIME=START44 THEN T44$76=.8*A{1994) IF RTIME= (START44+1.) THEN T44$76=2.9*A( 1994) IF RTIME=(START44*2.) THEN T44$76=2.4*A(1994) IF RTIME= (START44 + 3.) THEN T44$76=5. 4*A (1994) IF RTIME=(START44+4.) THEN T44$76=14.7*A{1994) IF RTIME=(START44+5.) THEN T44$76=14.*A(1994) IF RTIME=(START44+6.) THEN T44$76=7.6*A(1994) IT44$=PEXOG/2.11*T44$76 IDCT44$=A (1872) * { {. 5*IT44$) *J1L*IT44$+J2L*IT44S + J3L*IT4 4$+J4L*IT44$+J5L*IT44$+J6L*IT44$) IDC$=IDC$+IDCT44$ IF RTIME NOT= (START44+6.) THEN GO TO 950 PT$76=PT$76+(62.8*A(1994)) PT$H=PT$H+IT44$ + J1L*IT4 4$+J2L*.IT44$+J3L*IT44$+ J4L*IT4 4$*J5L*IT44$*J6L*IT44$+IDCT44$+J1L*IDCT44$+ J21*IDCT44$+J3L*IDCT44$+J4L*IDCT44$+J5L*IDCT4 4$+J6i*IDCT44$ 950 IF RTIME<START45 THEN GO TO 1005 IF RTIME> (START45 + 4.), THEN GO TO 1005 IF RTIME=START45 THEN T45$76=1.*A{1995) IF RTIME= (START45+ 1. ) THEN T45$7 6=2. * A (1 995) IF RTIME= (START45 + 2.) THEN T45$7 6=3 . * A (1995) IF RTIME= (START45 +3.) THEN T45$76=6.*A (1995) IF RTIME={START45+4.) THEN T45$76=3.*A (1995) IT45$=PEXOG/2.11*T45$76 IDCT45$=A (1872)* ( (.5*IT45$)+J1L*IT45$+J2L*IT45$+ J3L*IT45$+J4L*IT45$ + J5L<'IT45$ + J6L*IT45$) IDC$=IDC$+IDCT45$ IF RTIME NOT= (START45+4.) THEN GO TO 1005 PT$76=PT$76 +(15.* A{1995)) PT$H=PT$H+IT45$*J1L*IT4 5$+J2L*IT45$+J3L*IT45$+ J4L*.IT4 5$+J5L*IT45$*J6L*IT45$ + IDCT45$+J1L*IDCT45$+ J2L*IDCT45$+J3L*IDCT45$*J4L*IDCT45$+J5L*IDCT45$*J6L*IDCT45$ AGGREGATE FINANCIAL INFORMATION FOR ALL MAJOR ASSOCIATED TRANSMISSION PROJECTS ITRS1S76 - INVESTMENT IN MAJOR ASSOCIATED TRANSMISSION PROJECTS ($76) 1005 ITRS1$76=T1$76+T2$76+T3$76*T4$76+T6$76«-T8$76«-T9$76 + T10$76+ 1 T21$76*T31$76+T36$76*T38$76«-T4 0$76+T44$76*T45$76 • ITRS1$ - INVESTMENT IN MAJOR ASSOCIATED TRANSMISSION PROJECTS ITRS1$=PEXOG/2.11*ITRS1$76 KPST1$76 - NEW MAJOR TRANSMISSION PLANT IN SERVICE ($76) KPST1$7 6=J1L*KPST1$76+PT$76 KPIST1$H - NEW MAJOR TRANSMISSION PLANT IN SERVICE ($H) KPIST1$H=J1L*KPIST1$H+PT$H S.TPNOM - NOMINAL RATE OF SOCIAL TIME PREFERENCE 1010 STPNOM=(1.+A (1894) ) * (PEXOG/J1L*PEXOG) SENEBHC - HYDRO—GENERATED ENERGY CAPACITY HERE IF AVERAGE RAINFALL PERIOD SENERHC=SENERHAC HERE IF CRITICAL RAINFALL PERIOD IF A(2007) NOT= 0. THEN SENERHC=SENERHCC SENERBC - BORRARD»S ENERGY CAPABILITY SENERBC=SENERBAC SENERCC - HAT CREEK COAL CAPABILITY SENERCC=SENERCAC SENERKC - EAST KOOTENAY COAL ENERGY CAPABILITY SENERKC=SENERKAC SENERGC - GAS TURBINES ENERGY CAPABILITY SENERGC=SENERGAC SCAPH - HYDRO GENERATION CAPACITY CAPABILITY SCAPH=SCAPH IGENS74 - INVESTMENT IN GENERATION PROJECTS IGEN$76=IGEN$76 KPIS_$76»S KPISH$76=KPISH$76 KPISC$76=KPISC$76+KPISK$76 KPISG$76=KPISG$76 SENERCAP - TOTAL ENERGY CAPABILITY SENERCAP=S ENERHC+SENERBC+SENERCC +SEN ER KC+SEN ERGC ITRS1$76 - INVESTMENT IN ASSOCIATED TRANSMISSION PROJECTS 189 ITRS1$76=ITRS1$76 KPST1S76 - STOCK OF NEW MAJOR ASSOCIATED TRANSMISSION PROJECTS IN SERVICE KPST1$76=KPST1$76 SUBROUTINE COSTS THIS SECTION TAKES INFORMATION SUPPLIED FROM THE PLANNING SECTION AND ALLOCATES THE ASSOCIATED OPERATING AND CAPITAL COSTS ACCORDING TO CONVENTIONAL ACCOUNTING TECHNIQUES CQPFIX$ - FIXED OPERATING COSTS FOR COMPLETE SYSTEM IF NTIME=75 THEN COPFIX$=108.6 IF NTIME>=76 THEN COPFIX$={108.6*PEXOG/1.95) + { {PEXOG/2. 11} *A (1853) * (J 1L*KPISH$76+ (. 4* (KPISH$76-J 1L*KPISH$76) ) ) ) + ((PEXOG/2.11)*A(1854)* ( J1L*KPISC$76* {.4*(KPISC$76-J1L*KPISC$76))))+ {(PEXOG/2. 11) *A(1855)*(J1L*KPISG$76+ (.4*{KPISG$76-J1L*KPISG$76))})+ ( (PEXOG/2. 11) *A (1856) * (J 1L*KPIST$76+ (.4*(KPIST$76-J1L*KPIST$76))))* {{PEXOG/2.11)*A (1857)*(J 1L*KPISD$76+ (.4* (KPISD$76-J11*KPISD$76) ) ).) COPFIXU - FIXED OPERATING COSTS TO 230 KV LEVEL IF NTIME=75 THEN COPFIX1$=80. IF NTIME>=76 THEN COPFIX1$=(80.*PEXOG/1.95)* ((PEXOG/2.11)*A (1853)* (J1L*KPISH$76+ {. 4* (KPISH$76-J 1L*KPISH$76) ) )) + ((PEXOG/2.11) *A (1854) * (J 1L*KPISC$76 + (. 4*{KPISC$76-J1L*KPISC$76)))) + { (PEXOG/2. 11) *A (1855) * (J 1L*KPI SG$76+ (.4*{KPISG$76-J1L*KPISG$76))))+ {(PEXOG/2.11)*A(1856)*(J1L*KPST3$76+ (.4*{KPST3$76-J1L*KPST3$76) ) ) )• • ({PEXOG/2.11)*A (1857)*(J1L*KPISM$76 + {. 4* (KPISMS76-J 1L*KPISM$76) ) ) ) TWATER - WATER LICENCE COSTS IF NTIME=75 THEN THATER=8.2 IF NTIME>=76 THEN TW ATER= (PEXOG/1.95) * A { 1860) * (J 1L* SCAPH + (.4* (SCAPH-J1L*SCAPH) ) ) + (PEXOG/1.95)*A{1861)*SENERH 190 CGPVAR$ - VARIABLE OPERATING COSTS COPVAR$={PEXOG/2.11)*A{1862)*SENERC+ {PEXOG/2.11)*A{1863)*SENERK+ {PEXOG/2.11) *A (186 4)*SENERB+ (PEXOG/2.11)*A{1865)*SENERG* (PEXOG/2.11)*A{1878)*SENERM DEPREC$ - DEPRECIATION CHARGES IF NTIME=75 THEN DEPREC$=64.5 IF NTIME>=76 THEN DEPREC$=64.5* A (1874) * (J1L*KP.ISH$H + (.4* (KPISH$H-J1L*KPISH$H) ) ) • A (1875)*(J1L*KPISC$H+J1L*KPISG$H + (.4*(KPISC$H+KPISG$H-J1L*KPISC$H-J1L*KPISG$H)))* A {1876)* (J1L*KPIST$H+{.4*(KPIST$H-J1L*KPIST$H))) + A (1877)* (J1L*KPISD$H+ (.4*(KPISD$H-J1L*KPISD$H))) KDEP$76 - ACCUMULATED DEPRECIATION ON NEH NON-HYDRO-ELECTRIC FACILITIES FOR SCHOOL TAX PURPOSES IF NTIME=75 THEN DEPACC$H=0. IF NTIME>=76 THEN DEPACC$H=J1L*DEPACC$H+ (2.1 1/PEXOG* (DEPREC$-64.5-{A (1874)*(J1L*KPISH$H+(.4*(KPISHSH- J1L*KPISH$H)))))) TSCHOOL - SCHOOL TAXES IF NTIME=75 THEN TSCHOOL-=18. IF NTIME>=76 THEN TSCHOOL={18.*PEXOG/1.95)+ (A {1858}* (PEXOG/2.11 *{J1L*KPIS$76-J1L*KPISH$76- J1L*DEPACC$H))) TGRANTS - 'GRANTS' IF NTIME=75 THEN TGRANTS=3.3 IF NTIME>=76 THEN TGRANTS=A(1859)*J1L*YTOT TLAND - LAND TAXES IF NTIME=75 THEN TLAND=1. IF NTIME>=76 THEN TLAND=J1L*TLAND*(1.+ {1.5*A (1972))) TLOCAL - ALL LOCAL TAXES TLOCAL=TSCHOOL+TGRANTS*TLAND INTEREST CHARGES INTOLDB - ANNUAL INTEREST TO 1976 PAYMENTS REMAINING ON BONDS ISSUED PRIOR IF HTIHE=75 THEN INTOLDB= A ( 1 867) *A (1 86 8) *A { 1 86 9) 191 IF NTIME=76 THEN INTOLDB=A { 1 867) *A { 1 86 8) * { (J1L*INT0LDB+25.)- (•5*1NTRED$H)-(.5*J1L*INTRED$H)) IF NTIME>=77 THEN INTOLDB=J 1L*INTOLDB— JA (1 867) *A <1 868) * (. 5* (INTRED$H*J 1L*INTBED$H) ) ) LOLD$H - STOCK OF DEBT ISSUED PRIOR TO 1976 STILL OUTSTANDING AT END OF EACH PERIOD IF NTIME=75 THEN LOLD$H=2990.32 IF NTIME>=76 THEN LQLD$H= J1L*LOLD$H-LOLDM$H SFPAYMT$ - ANNUAL SINKING FUND PAYMENT AND ADDITIONAL FUNDS REQUIRED FOR BONDS MATURING BEFORE 1982 IF NTIME=75 THEN SFPAYMT$=34. 6*A (1 867) IF NTIME=76 THEN SFPAYMT$=35. 3 *A (1 867) IF NTIME=77 THEN SFPAYMTJ=54. 0*A (1 867) IF NTIME=78 THEN SFPAYMT$=81.9*A (1867) IF NTIME=79 THEN SFPAYMT$=49. 3*A (1 867) IF NTIME=80 THEN SFPAYMT$=*4U. 3*A (1 867) IF NTIME=81 THEN SFPAYMT$=69. 7*A {1 867) IF NTIME>=82 THEN SFPAYMT$= (A (1870) *A (1 867) *LOLD$H) + (AJ1871)*J5L*LNEW$H) FINREQ - FINANCIAL REQUIREMENTS FINREQ=I$+SFPAYMT$+(A(1867)*LMATWOSF) FINREQB - FINANCIAL REQUIREMENTS TO BE MET BY DEBT FINANCING FINREQB=FINREQ-YTOT+CGSTS$—DEPRECS LNEW$H - STOCK OF POST-75 NEW BONDS OUTSTANDING IF NTIME=75 THEN LNEW$H=476.6 IF NTIME>=76 THEN LNEW$H=J1L*LNEW$H+FINREQB INT$ - TOTAL INTEREST CHARGES INT$=INTOLDB+ (A (1868) *LNEW$H*A (1872)) -IDC$ COSTS$ - TOTAL OPERATING AND CAPITAL COSTS COSTS$=COPFIX$+TLOCAL+TWATER+COPVAR$-»-DEPREC$+INT$ C1KWH$76 - NET COST PER KWH GENERATED C1KWH$76={2.11*(COSTS$* (COVERAGE*INT$)-YEXPORT))/ 192 (SENER*PEXOG) C2KWHS76 - COST PES KWH GENERATED C2KWH$76={2.11*{COSTS$+{COVERAGE*INT$)))/(SENER*PEXOG) THIS SECTION IS USED TO DO AN ECONOMIC ANALYSIS OF THE IMPLICATIONS FOR PRESENT AND FUTURE QUANTITIES AND COSTS OF CHANGES IN DEMAND GROWTH AND THE RESULTANT READJUSTMENT IN PROJECT PLANNING ANNUAL PRESENTLY UNCOMMITTED OPERATING COSTS (ALL VARIABLE AND POST-74 FIXED) TO SERVE LARGEST CUSTOMERS A{1861)*SENERH+A(1860) *SCAPH + A ( 1864) * SENERB+A (1862) *SENERC +A {1863) *SENERK*A (1865) * SENERG+A{1853)*KPISH$76+A(1854)*KPISC$76+A(1855)* KPISG$76+A{1856}*KPST3$76+A(1857)*KPISM$76- (A(1879)*DEXPORT) C02S76 - ANNUAL PRESENTLY UNCOMMITTED OPERATING COSTS (ALL VARIABLE AND POST-74 FIXED) TO SERVE SMALLEST CUSTOMERS C02$76=C01$76 + A(1856)*KPST4$76+A (1857)*(KPISD$76-KPISM$76) KPVELEC3 - PRESENT VALUE OF ACTUAL ENERGY PRODUCED (KWH) KPVELEC3=(1.*A{1894))*J1L*KPVELEC3+SENER* { (1. +A{1894) ) **,5) IF K7=H9 THEN KPVELEC3=KPVELEC3/({ 1.+A (1894) ) **{K7-2) ) KPVELEC4 - PRESENT VALUE OF ACTUAL CAPACITY PRODUCED (MW) KPVELEC4=(1.+A(1894))*J1L*KPVELEC4+DPEAK* {(1.+A{1894) )**.5) IF K7=M9 THEN KPVELEC4=KPVELEC4/ { ( 1. +A (1 894) ) ** (K7-2) ) KELEC3 - STOCK OF CAPITAL TO SERVE LARGEST CUSTOMERS KELEC3={J1L*KELEC3+IGEN$76*ITRS$76 + ITR F1$76 + (.5*IMISC$76) ) * {1.-A (1850) ) KELEC4 - STOCK OF CAPITAL TO SERVE SMALLEST CUSTOMERS KELEC4=(J1L*KELEC4+IGEN$76*ITRS$76+ITRF$76+IDIST$76)* (1.-A(1850) ) KPVC3$76 - PRESENT VALUE OF COSTS ASSOCIATED WITH SUPPLYING LARGEST CUSTOMERS KPVC3$76=(1.+A(1894))*J1L*KPVC3$76+(C01$76+{A(1850)* (J1L*KELEC3+IGEN$76+ITRS$76+ITRF1$76+{.5*IMISC$76)))+ ( (A (1890) +A (1895) ) *.5* (KELEC3+J 1L*KELEC3) ) } * ((1.+A(1894) ) **.5) C01$76 - C01$76= IF K7=M9 THEN KPVC3$76=KPVC3$76/((1.+A (1894) )**{K7-2) ) KPVC4$76 - PRESENT VALUE OF COSTS ASSOCIATED WITH SUPPLYING 193 SMALLEST CUSTGMERS KPVC4$76=(1.+ A(1894))*J1L*KP¥C4$ 76 + (CO2$76*(A(1850)* (J1L*KELEC4*IGEN$76+ITRS$76+ITRF$76+IDIST$76))+ C(A (1890)+AC1895))*.5* (KELEC4+J1L*KELEC4)))* (<1.*A(1894))**.5) IF K7=M9 THEN KPVC4$76=KPVC4$76/{ { 1.+A (1 894) ) ** (K7-2) ) SUBROUTINE RATES THIS SECTION CALCULATES REVENUES AND RATES THAT ARE ESTABLISHED BY B C HYDRO IN RESPONSE TO THE COSTS FACING IT AND ITS FINANCIAL POLICIES DETERMINE REVENUES FROM ELECTRICITY SALES YRES - REVENUE FROM RESIDENTIAL SALES YRES=PRES*DRES YGEN - REVENUE FROM GENERAL SALES YGEN=PGEN*DGEN YBULK - REVENUE FROM BULK SALES YBULK=PBULK*DBULK YWKPL - REVENUE FROM WKPL SALES YWKPL=PWKPL*DWKPL YEXPORT - REVENUE FROM EXPORT SALES YEX PORT=PEX PORT *DEX PORT YTOT - TOTAL REVENUES YTOT=YRES+YGEN+YBULK+YWKPL+YEXPORT MISS— FRACTION OF REVENUE SURPLUS/DEFICIT MISS=(COSTSS+(COVERAGE*INT$) -YTOT) / (YTOT-YEXPORT) DETERMINE AVERAGE RATE LEVELS ($/KWH) PEES - AVERAGE RESIDENTIAL RATE 194 IF (NTIME.EQ.75) PRES=.023 IF(NTIME.EQ.76) PRES=.027 IF(NTIME,GE.77) PRES=J1L*PRES* (1.+MISS) PGEN - AVERAGE GENERAL .RATE IF (NTIME.EQ.75) PGEN=.020 IF(NTIME.EQ.76) PGEN=.023 IF (NTIME. EQ.77) PGEN = .026 IF(NTIME.GE.78) PGEN=J1L*PGEN* (1.+MISS) PBULK - AVERAGE BULK RATE IF(NTIME.EQ.75) PBULK=.007 IF (NTIME.EQ.76) PBULK=.010 IF(NTIME.EQ.77) PBULK=.011 IF (NTIME. EQ. 78) PBULK=.012 IF(NTIME.EQ.79) PBULK=.0134 IF (NTIME.GE. 80) PBOLK=J 1L*PBULK* (1.+MISS) PIKPL - AVERAGE WEST KOOTENAY POWER AND LIGHT RATE IF (NTIME.EQ.75) PSKPL=.0146 IF (NTIME.EQ.76) PWKPL=.0186 IF(NTIME.EQ.77) PWKPL=.0195 IF (NTIME. GE. 78) PWKPL=J 1 L*PWKPL* (1.+MISS) PEXPORT - AVERAGE EXPORT PRICE IF (NTIME.GE.75) PEXPORT= A {1879) * (PEXOG/1.77) CONVERT CURRENT DOLLAR RATES TO $76 RATES PRES$76=PRES*2.11/PEXOG PGEN$76 = PGEN*2. 11/PEXOG PBULK$76=PBULK*2.11/PEXOG PWKPL$76=PWKPL*2.11/PEXOG PEXP$76=A (1879) YRESMCP - REVENUE FROM RESIDENTIAL SALES UNDER FULL MCP YRESMCP=A(2014) *PEX0G/2. 11*DRES/1000- 195 YGENMCP - REVENUE FROM GENERAL SALES UNDER FULL MCP YGENMCP=A (2016) *PEXOG/2.11*DGEN/1000. YBULKMCP - REVENUE FROM BULK SALES UNDER FULL MCP YBULKMCP=A(2018)*PEXOG/2.11*DBULK/1000 - YSURPMCP - ADDITIONAL B.C. HYDRO NET INCOME UNDER FULL MCP YSURPMCP=YRESMCP+YGENMCP*-YBULKMCP*YWKPL+YEXPORT -COSTS$-(COVERAGE*INT$) YTOTSURP - TOTAL B.C. HYDRO NET INCOME UNDER FULL MCP YTOTSURP=YSURPMCP+(COVERAGE*INT$) YTOTMCP - TOTAL REVENUE FROM SALES UNDER FULL MCP YTOTMCP=YRESMCP*YGEN MCP+ YBULKMCP* Y WKPL*-Y EXPORT IF(NTIME.LT.81) YTOTMCP=YTOT

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