UBC Theses and Dissertations

UBC Theses Logo

UBC Theses and Dissertations

An application of marginal cost pricing principles to B.C. Hydro Osler, Sanford Lake 1977

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

Item Metadata

Download

Media
831-UBC_1977_A8 O84.pdf [ 14.01MB ]
Metadata
JSON: 831-1.0094435.json
JSON-LD: 831-1.0094435-ld.json
RDF/XML (Pretty): 831-1.0094435-rdf.xml
RDF/JSON: 831-1.0094435-rdf.json
Turtle: 831-1.0094435-turtle.txt
N-Triples: 831-1.0094435-rdf-ntriples.txt
Original Record: 831-1.0094435-source.json
Full Text
831-1.0094435-fulltext.txt
Citation
831-1.0094435.ris

Full Text

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 R e q u i r e m e n t s f o r t h e Degree o f Master o f A r t s  in  The F a c u l t y o f G r a d u a t e 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 a s c o n f o r m i n g to t h e 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 J u n e , 1977 ( ^ c ^ S a n f o r d Lake O s i e r ,  1977  In  presenting  this  an a d v a n c e d  degree  the  shall  I  Library  f u r t h e r agree  for  scholarly  by h i s of  this  written  at make  that  thesis  freely  may It  is  University  F m n r m i  of  British  June 24, 1977  of  of  Columbia,  British for  for extensive by  gain  nc  Columbia  shall  the  that  not  requirements I  agree  r e f e r e n c e and copying  t h e Head o f  understood  permission.  of  fulfilment  available  be g r a n t e d  financial  2075 Wesbrook Place Vancouver, Canada V6T 1W5  Date  it  permission  purposes  for  in p a r t i a l  the U n i v e r s i t y  representatives.  Department The  thesis  of  this  be a l l o w e d  or  that  study. thesis  my D e p a r t m e n t  copying  for  or  publication  without  my  ABSTRACT  The  purpose o f  methodology supplying  to  is  the  to  develop  marginal  i s  to design  marginal  economic c o s t . The r e s u l t i n g  apply costs  a of  h y d r o - e l e c t r i c system  Hydro and Power A u t h o r i t y used  s t r u c t u r e i n which  and  economic  i n the predominantly  Columbia  information  rate  paper  determine  electricity  of t h e B r i t i s h This  this  (B.C.  an e c o n o m i c a l l y  price i s set egual  Hydro). efficient  to  marginal  i m p l i c a t i o n s f o r t h e growth r a t e i n  e l e c t r i c a l demand and c o s t s a r e t h e n c a l c u l a t e d . A  computer  simulation  model i s b u i l t  demand f o r e c a s t t o 1990, p l a n s in  a  cost  minimizing  and  the operating  accounting  costs  accordance with Marginal various  changes.  are determined  economic  system  costs  to  the  f o r the present amounts,  are  policies.  calculated  by  introducing  demand f o r e c a s t and e x a m i n i n g t h e  value when  of  change  energy  peak  economic  divided  involved, give estimates and/or  annual  and t h e r a t e l e v e l s a d j u s t e d i n  electricity in  a  fashion subject to technical constraints  the Authority's f i n a n c i a l  These  the e l e c t r i c  p o l i c i e s o f B.C. Hydro. The a s s o c i a t e d  alterations  implications  and o p e r a t e s  which, once g i v e n  of  by the  demand  costs the  unit  of  such  guantity costs  of  of a  for various classes of  customers. These m a r g i n a l redesigned marginal  rate  s t r u c t u r e i n which m a r g i n a l  costs while  accounting  economic c o s t s a r e then  average p r i c e s continue  c o s t s . By a p p l y i n g  various  incorporated  in  p r i c e s egual to  estimates  a  these  egual  average  of long  r u n own  price e l a s t i c i t y by  marginal  forecast  of demand, the impact  price  changes  on demand  can be determined.  w i l l , i n t u r n , a f f e c t system design and  growth  caused  T h i s nes demand operation  and  thus u l t i m a t e l y , c o s t s . The  r e s u l t o f t h i s a n a l y s i s i s t h a t t h e l a r g e r users  w i t h i n each c l a s s and higher  marginal  within  the  system)  face  substantially  r a t e s from those now i n e f f e c t . I n p a r t i c u l a r ,  the economic a n a l y s i s a t t a c h e s f a r g r e a t e r weight t o t h e component  of  demand  in  than does the accounting estimates,  this  rate  reduces  average  real  per KWH,  and reduces  17.1 t o 11.2 b i l l i o n conclude  approach. Under the structure  reform in  reduces the  accounting c o s t s from  the gross debt historic  median  elasticity  the e l e c t r i c a l  1976-1990  period,  18.1 t o 16.5 m i l l s  outstanding  in  1990  from  dollars.  t h a t there e x i s t s s u b s t a n t i a l gains i n s o c i a l  welfare t o be o b t a i n e d from r e d e s i g n i n g B.C. Hydro's rate s t r u c t u r e s .  energy  the e n e r g y - c r i t i c a l B.C. Hydro system  growth r a t e from 9.0 t o 7.0 percent  We  (both  electrical  iv  TABLE OF CONTENTS ^•Xntirociiictioii  •• * *••• **  •• * *• •  • *••'*••»**.••*.••*'•'*•• 1  2. B.C. Hydro Today  4  2 • 1 I n t r o d u c t i o n • • • ** * • * * • 2.2 P a s t  And P r e s e n t  * ••- • • * •  ••**  ••• *• • *•» * * 4  P o l i c i e s Of The E l e c t r i c  2.3 Summary  ..........25  3. T h e o r y And M e t h o d o l o g y 3.1  S e r v i c e ...6  Of M a r g i n a l C o s t  Emergence Of T h e T h e o r y O f M.C.P.  Pricing  ........27  .  3.2 Emergence Of The M e t h o d o l o g y And A p p l i c a t i o n  27 Of M.C.P.  ........................................32 3.3 D e v e l o p i n g 3.4* Summary  An M.C.P. M e t h o d o l o g y  F o r B.C. Hydro  ....... .... . . . . . . . . . . . . .... ...... ............ i*5  4. The S t r u c t u r e Of T h e Model  ....... 46  4.1 I n t r o d u c t i o n  ....46  4.2 POLD1 And P0LS1  ..........  .........  4 . 3 DEMAND ^ • 4'  S  Ul?  PIJY  35  48 50 ••••5'1  " • • • • • * * * - • • • • • • • • * . * « * * •  4.5 MCOST 4.6 APPROVE  56 .............................................62  4.7 COSTS  63  4.8 BATES  ........69  5. The R e s u l t s  ......70  5.1 P r o j e c t C o s t i n g And R a n k i n g . . . . . . . . . . . . . . . . . . . . . . . . . 70 5.2 C o n v e n t i o n a l A c c o u n t i n g 5.3 D e t e r m i n a t i o n 6. A p p l i c a t i o n s  Projections  Of M a r g i n a l C o s t  77  ......................87  ...........................................97  6.1 R a t e S t r u c t u r e D e s i g n 6.2 Demand And System  Response  .97 104  7. Summary And C o n c l u s i o n s Bibliography  ................115 ..119  A. A p p e n d i x A  .........127  B. A p p e n d i x B  128  C. A p p e n d i x C  ....129  D. A p p e n d i x D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136 D.1  List  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 M o d e l . . . . . . . . . . . . . . . . . . . . . . . . . 146  vi  L I S T OF TABLES  Table  1: C o s t i n g Of G e n e r a t i o n  T a b l e 2:  1976-1990 P r o j e c t i o n  T a b l e 3: S e n s i t i v i t y 1976-1990 P e r i o d Table  Of Key F i n a n c i a l  V a r i a b l e s ..79 I n The  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81 Changes:  1 976-1990 . .. . .  83  Economic C o s t s F o r V a r i o u s Demand Shocks 89  T a b l e 6: A S u r v e y Of E s t i m a t e d Elasticities  ..........71  A n a l y s i s On A v e r a g e Cost/KWH  4: R e l a t i v e C o s t  T a b l e 5: M a r g i n a l  Projects  Of E l e c t r i c i t y  Long  Hun Own  Price  Demand  ......108  T a b l e 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 Table  8; M a r g i n a l And A v e r a g e P r i c e s  Table  C-1: Impact  ............111  Of E l e c t r i c i t y  On B.C. Hydro Of A l t e r n a t i v e  Rate  Structures Table  C-2: Impact  Structures  .......117  130 On C u s t o m e r s Of A l t e r n a t i v e  Rate ..........134  L I S T OF FIGURES  Figure  1  ..................................................98  ACKNOWLEDGEMENTS  I am d e e p l y i n d e b t e d t o many f o r a s s i s t a n c e in the preparation of this paper. John Helliwell provided the general guidance, i n s p i r a t i o n and c o n f i d e n c e which made i t a l l p o s s i b l e . G e r r y May introduced me to the w o r l d o f c o m p u t e r m o d e l l i n g and s e r v e d as an invaluable sounding board during the conceptualization period., Ernie Berndt provided assistance with l a t e r s t a g e s and carefully reviewed preliminary drafts. Cheerful and efficient secretarial and t e c h n i c a l s e r v i c e s were provided by J a n e y Ginther. A variety of o f f i c i a l s a t B.C. H y d r o gave f r e e l y o f t h e i r t i m e t o h e l p me understand their utility and t o r e v i e w an initial draft. Not l e a s t important, the Office o f Energy Conservation within the federal Department of Energy, M i n e s and Resources provided financial and moral support throughout the researching and writing o f t h i s t h e s i s . Many t h a n k s t o you all.  1  INTRODUCTION In r e c e n t about  the  utilities.  actions  fulfil  paid  this  responsible  lower  rate structures  block classes  suggest  electric  has  around  and  utilities  with  some  structures primary  that  and  paper  production. the  a t t e n t i o n h a s been  critics  America  holding  long  them  ago a d o p t e d a  meant t h a t , b o t h  Although  w i t h i n and  the consumption t h e now  usually  s t r u c t u r e f o r one  the primary emphasis methodology  the  criterion  condition  resulting  less  Much, o f  by  that  will  for  be  the  be  f o r determining will  a l s o be  on and  given  economically  employed  efficient  of s o c i a l  must e g u a l  costs  particular  will  to  appropriate  in  o f economic e f f i c i e n c y .  this  analysis  growth.  maximization  marginal  proposed  be t o use e c o n o m i c  rate  a  marginal p r i c e o f a product  determine  will  have f o r demand  the  and t h e means  high  based".  structure i s that  a necessary  the  rates.  economic c o s t s , c o n s i d e r a t i o n  rate  resources  "cost  applying  implications  rate  centred  remains predominant and i s j u s t i f i e d  appropriate  the  of  American  i n North  B.C. Hydro. A l t h o u g h  allocating  The  format  as being  an  growing  customers, the greater  purpose o f t h i s  developing  that  o f many N o r t h  structure. This  of  this  utilities  utility,  this  concern  growth  utilities  rate  public  the u n i t p r i c e o f e l e c t r i c i t y .  The to  been  demand. C o n s i d e r a b l e  f o r "excessive"  pronounced, the  by these  forecast  Most e l e c t r i c  between  has  and p o l i c i e s  projected  to their  declining  there  Much o f t h e c r i t i c i s m  growth r a t e s to  years,  paper  This  means  allocation  welfare  i t s marginal w i l l focus  associated  designing  of  i s that the social  cost  on how b e s t t o  with  supplying  2  electricity. The  selection  influenced, many  one  B.C.  Hydro  as  n a t u r a l l y , by i t s g e o g r a p h i c  reasons,  analysis.  of  however,  which  make  B.C. H y d r o ' s f o r e c a s t  the  case  study  proximity.  There  into  independent  increasing  growth r a t e  analysis  opposition  for electricity  throughout  the  appropriateness  structure could help to c l a r i f y  some t h e i s s u e s  Secondly, its  existing  generation type  of  the and  of  very growing  characteristic utilities.  is of  unusual  of  particularly  several  difficult  Finally,  the  other  technical  by  world  i t s  rate  being discussed. with  hydro-electric  context,  this  i t  Canadian  i s  electric  that  marginal  cost  hydro-electric  systems  are  To t h e b e s t o f my  knowledge,  1  availability B.C.  Hydro  of  has  assistance  i n a variety  several  provided  i n f o r m a t i o n t o undertake  officials  of  o p p o r t u n i t i e s . While  (falsely)  the ready c o - o p e r a t i o n ,  Hydro  t h e p r o v i n c e . An  on  important  t o perform.  public  extensive publications sufficient  a  predominantly  none has been done t o d a t e .  many  reliance  in  I t h a s been s u g g e s t e d  analyses  addition,  heavy  i s  plans a r e  n a t u r e o f t h e B.C. Hydro s y s t e m ,  sources, presented s p e c i a l system  were  i t au i d e a l c a n d i d a t e f o r  o f t h e h i g h e s t on t h e c o n t i n e n t , a n d i t s e x p a n s i o n  running  was  recent me  with  this  analysis. In  and  interest  of areas contributed  of  greatly  to my u n d e r s t a n d i n g o f t h e u t i l i t y . The  next c h a p t e r c o n t a i n s a d e s c r i p t i o n  currently exists,  including  forecasts e l e c t r i c a l  1  a review  of  demand, d e t e r m i n e s  See, f o r example, B a r n e t t (1977).  the  o f B.C. Hydro way  in  i t s expansion  as i t  which  i t  programme,  3  finances  i t s g r o w t h and s e t s  what e c o n o m i c t h e o r y structures, developed employed model it  various  to a l l o c a t e costs,  The t h i r d way  that  i s used  and o u t l i n e s  generates.  sixth  structure, chapter  and  the cost  chapter  and a p p l i c a t i o n s  concluding paper  The  and p r e s e n t  of  methodologies  i n t h i s a n a l y s i s . The f o l l o w i n g  of t h e r a t e  this  suggests i n the  assesses  implications  The  rates.  the  chapter  appropriate that  approach  to  allocation results  examines  some  of  be  that the  of these r e s u l t s - f o r the design  briefly  main  acceptance of the underlying  been  two c h a p t e r s d e t a i l t h e  of f u t u r e  on  rate  have  and f o r t h e f o r e c a s t i n g  comments  examines  summarizes t h e the  demand.  results  of  r e l e v a n c e and l i k e l i h o o d o f  principles.  a  ZJL B.C.  2.1  Introduction British  Columbia  Crown c o r p o r a t i o n It  was  f o r m e d by  serving  British  by  t o be  invalid  the  union  was  Under t h i s an  amalgamation o f  Company  by  the  Hydro and Act,  B.C.  extensive a  inter-  and  city  railway  and  Treaty.  By  intrathree  original  bus  given  gas  B.C.  percent  of  the  population  provincial  mandate o r itself  recently  owned u t i l i t y  1964  an  area  of B r i t i s h has  o b j e c t i v e s of stated might be  that  was  of  but the  Act. broad  powers  and  At  system,  an  distribution  with  the  has  services.  passenger s e r v i c e , a s m a l l  government  formal  British  Columbia,  public u t i l i t y  Hydro i s t h e  then  corporation  passage i n  far i t s largest responsibilities, s e r v i c e area.  a  1962.  legislation  of B r i t i s h  the  as  utilities  t h e Crown  Authority  of  created  Columbia i n  electric  and  dams i n c o n n e c t i o n  i n Canada, s e r v i n g  publicly  Power  was  privately-owned  Supreme C o u r t  regional  utility  basic  two  Limited  system  i t operates  The  British  the  Hydro was  present  electric  of  f o r m a l l y cemented w i t h  Columbia  developed  government  Power C o m m i s s i o n . The  held  British  Power A u t h o r i t y  a r e a s i n B.C.:  Electric Columbia  Hydro and the  the  different  Columbia  has  HYDRO TODAY  freight  Columbia  River  however, l i e i n  third  largest  containing  more  the  electric than  90  defined  the  Columbia. never f o r m a l l y B.C. the  summarized  Hydro. The typical as  Authority  f u n c t i o n of  follows:  a  5  To s u p p l y t h e demands o f i t s c u s t o m e r s f o r energy at the lowest cost consistent with safety to i t s e m p l o y e e s and p u b l i c , good q u a l i t y o f s e r v i c e to its customers, and subject to t h e s o c i a l , e c o n o m i c and e n v i r o n m e n t a l p o l i c i e s o f t h e Government. (B.C. H y d r o , 1975b, 12)  Final with  decision-making  a Board o f the  e n e r g y . The  Authority  and  for  be  B.C.  capital.  of  hydro-electric securities  the  a  special  generating  are  sold outside  the  province  approval.  2  In  line are  the case  undertake,  of  approval  external authorities.  other  school  tax  except taxes  equivalent  e x e m p t i o n on Its  guaranteed  same  with  the  i t s biggest  bonds by  the  on  of the  corporation,  installations.  unconditionally  March over  through  31, $4  1976,  expenses,  B.C.  billion.  bonds i s s u e d  Hydro's revenues i n t h e its  railway  a l l f e d e r a l taxes  any  rates  one  I t g e n e r a l l y pays t h e as  the  for  case of  appropriate  taxes  members  responsible  determine  Hydro s e e k s t o  to  five  vested  and  other  Province  of  Columbia.  As o f  financed  from  provincial  exception  to  external  Hydro i s s u b j e c t  and  minister  power  n a t u r a l gas  projects that  income and  slightly  and  to  required  British  full  subject  B.C.  local  has  cabinet  i t s s e r v i c e s . Only i n the  prices  specific may  provincial  of e l e c t r i c i t y  these  Hydro i s  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  including  charged  a u t h o r i t y w i t h i n B.C.  but  Hydro's t o t a l  Of or  this,  only  after  more t h a n $3  acquired  1975-76 f i s c a l a  assets  by  year  special  the  stood  at  billion  was  Authority.  slightly subsidy  B.C.  exceeded from  the  The B r i t i s h C o l u m b i a E n e r g y C o m m i s s i o n i s empowered t o review certain d i s c r i m i n a t i o n c o m p l a i n t s and t h e p r o v i n c i a l government intends to establish a permanent Legislative Committee to examine t h e l a r g e Crown c o r p o r a t i o n s . 2  6  provincial transit  government t o c o v e r  o p e r a t i o n s (see appendix  2.2 P a s t And P r e s e n t P o l i c i e s  2.2.1  Demand Until  product.  recently,  between  At  this  the  for  to  the  time p e r i o d . the  ratio  period. load  or  growth  in  energy  time  {say energy  the  will  demand  Since  demand  of  for i t s  (usually  one h o u r ) .  growth.  the t o t a l  one  year)  within  It  clearly  this  energy without  the s p e c i f i e d  Peak  t h e maximum r a t e o f e n e r g y i s  demand,  on  consumption measured  through the l o a d  in  factor,  a v e r a g e demand i n k i l o w a t t s s u p p l i e d  during a  to  in  the  this  be used  maximum paper  in  demand  the  terminology  to either  occurring  that  t h e demand f o r e l e c t r i c i t y ( o r general  t o b o t h components o f e l e c t r i c a l  specifically  the  I t i s measured i n k i l o w a t t - h o u r s .  Throughout  peak  o f B.C. Hydro h a s  reflects  period  r a t e o f use o f t h a t  period  demand)  refer  service  The two c o n c e p t s a r e r e l a t e d of  designated  electric  electrical  i n a g i v e n time p e r i o d  a  bus  Service  and peak demand components  o t h e r hand, r e f l e c t s  kilowatts.  with  A) .  Of The E l e c t r i c  rapid  reguirements i n a given regard  associated  stage i t i s important to d i s t i n g u i s h  the energy  demand  loss  for Electricity  experienced r e l a t i v e l y  The  the  will  be  economic  sense  and  demand, w h i l e t h e e n e r g y used  when  referring  component.?  i t s formation  in  1962,  B.C.  Hydro's  sales  of  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 h e r e b e c a u s e o f t h e common usage o f t h e term "demand" i n t h e 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 o n l y t o what I h a v e c a l l e d "peak demand". 3  7  electrical billion of 9.8  energy  to the  k i l o w a t t hours, percent.  has  had  an  to  4.1  million  and  occurring  again  i n 1975  commercial the b u l k past,net  class  the  energy  20  and  than  electrical  three  b u l k . The  large  5 percent  1962-1976  18  then  65  of the  industrial  1.2  energy  1965-1970  provincial  total.  share  of  the  to s u p p l y  has  the  by  now  natural  gas  Hydro's share  than  half  built  and  over  B.C.  Although  total  just  to i t s  of  the  present  s u p p l y i n g the  commercial customers, the  which  whereas In  rose s l i g h t l y  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 market  a l l  s y s t e m s have u s u a l l y  followed  less  users,  consumers.  O i l continues  grown f r o m  classes:  sales.*  the  market,  fairly  comprises  industrial  of t o t a l  is  customer  industrial  electricity.  o f r e s i d e n t i a l and  large  demand  actual reductions  general c l a s s  electricity  percent.  market h a s  provide  the  energy  major  period,  provincial and  in  with  s a l e s to o t h e r e l e c t r i c a l  total  not  rate  expanding from  place  1974,  of  market s u p p l i e d by  does  growth  peak o n e - h o u r  percent,  took  and  the  contains  percent  percent  20.6  1976.  electricity  majority  percent  1973  among  at close to  of the  with  and  energy  During  half  9.4  customers p l u s the s m a l l e r  less  stands  ten  in  general  represented  B.C.  same p e r i o d , t h e  consumption  split  residential,  compounded  to  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  At p r e s e n t , evenly  average annual  growth r a t e o f  consumption exceeding period  an  Over t h i s  annual  p u b l i c have i n c r e a s e d f r o m 5.5  vast  Authority part of  substantial  the  hydro-  * I n 1974 a r e c o r d s h a r e o f 10 p e r c e n t of t o t a l s a l e s went to o t h e r s y s t e m s due t o 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 t h e s e o t h e r areas.  8  electric  or  wood  waste  generating  enlarged  share o f the e l e c t r i c i t y  Hydro's  acquisition  capacity.  field  Part  s  i s accounted  of t e n small e l e c t r i c  of  this  f o r by B.C.  utilities  during  this  period. In the  forecasting future  methodology  demand g r o w t h , B.C. Hydro  i t c l a i m s t o have employed s u c c e s s f u l l y  past. This process involves extrapolation modified  by known o r e x p e c t e d  regional, include in  customer  class,  based  developments.  electricity  a r e not e x p l i c i t y  resulting extended  basis.  short-term to f i v e ,  ten, or  use  on  a  on p o p u l a t i o n t r e n d s , c h a n g e s  Expected  energy  i athe  Factors studied  u s a g e , e c o n o m i c t r e n d s , and known  industrial  on  o f past growth t r e n d s ,  developments i n energy  and p r o v i n c i a l  numbers o f c u s t o m e r s  per customer  relies  changes  included  in  and peak  fifteen  in this  and  probable  the  price  analysis.  of The  demand f o r e c a s t s a r e t h e n  years  for  system  planning  purposes. In and  i t s 1975  Report  T r a n s m i s s i o n Requirements  a l t e r n a t i v e econometric the  first,  regressed  H 9 7 5 b ) . B.C. Hydro  methodologies  t h e demand f o r t o t a l  on t h e r e a l G r o s s  years.  The  slightly  t o take account  the  o f t h e Task F o r c e on F u t u r e  resulting  forecast  of r e a l  develops  two  f o r demand f o r e c a s t i n g . I n  and e l e c t r i c  Provincial  of a n t i c i p a t e d  energy  i n B.C. i s  Product f o r the  energy-product  B.C. economy and h i g h e r e n e r g y  Generation  coefficient, structural  prices,  i s then  G.P.P. i n o r d e r t o d e t e r m i n e  future  past  20  reduced  changes applied  in to a  electricity  demand. The two major i n d u s t r i a l s u p p l i e r s a r e t h e Aluminum Company o f Canada ( A l c a n ) and Cominco w i t h 18 and 9 p e r c e n t , r e s p e c t i v e l y , of t h e p r o v i n c i a l e l e c t r i c a l e n e r g y c a p a b i l i t y . Both u s e hydroelectric sources and help supply r e g i o n a l requirements with their surplus capacity. 5  9  The a l t e r n a t i v e econometric John  Wilson  (1974  electrical  energy  that of s u b s t i t u t e forms variables.  In  this  of way,  for  the  employed  by  ten  energy)  and  changing  conventional  energy  economic  prices  were  determining  and  growth  its  official  methodology.  Hydro Total  demand ( i n c l u d i n g system l o s s e s and the need  Hydro was  annual r a t e of 9.3  he  explicitly  to supply shortages a n t i c i p a t e d by a p r i v a t e e l e c t r i c a l s u p p l i e d by B.C.  time-  (both i t s own  on  forecasting  Dr.  years,  demand f o r e c a s t i n the 1975-1990 p e r i o d , B.C.  its  electrical  last  demand on p r i c e  c o n s i d e r e d i n demand p r o j e c t i o n s . I n electricity  performed  ) , an o u t s i d e c o n s u l t a n t . Using pooled  s e r i e s and c r o s s - s e c t i o n a l data regressed  approach was  expected  percent over  to i n c r e a s e  this  period.  constant system load f a c t o r , peak demand was  6  utility)  by  an  average  By  assuming  a  a n t i c i p a t e d to r i s e  at the same r a t e . By  way  of comparison,  demand f o r e c a s t using the {which  assumes  B.C.  Hydro's median e l e c t r i c  adjusted  with  coefficient  p o p u l a t i o n and economic growth r a t e s e g u i v a l e n t  to those i n the 1953-1973 period) was study,  energy-product  energy  its  explicit  8.6  consideration  percent.  The  of p r i c e s , was  Wilson lower  still.  2.2.2  System Planning  B.C., Hydro's September 1976 comparable e l e c t r i c a l energy f o r e c a s t (using the same 1975 base) assumes a growth r a t e o f 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 t o o b t a i n f u l l d i s a g g r e g a t i o n of t h i s new estimate and because I wish t o maintain c o n s i s t e n c y with other sources of i n f o r m a t i o n . Appendix C, however, does use t h i s updated l o a d f o r e c a s t . 6  10  At half  i t s formation,  a  small  demands  on  interconnections been  forged  generating the  main  between  time,  quadrupled.  the  Strong have  and much l a r g e r g e n e r a t i o n  projects  have been  added  not yet connected  with  integration  in  {the P r i n c e of  the  1978.  load centre  Super t - K i t i mat-Terr ace  province)  Other  the province  very  are supplied  For t h e purposes of t h i s  integrated  following  that  sections  part  generators.  almost  by a s e r i e s  isolated  system  throughout  have  contained  the p r e v i o u s l y  North-west  the  system  s t a t i o n s . Since  system  t o t h e s y s t e m . The one major the  electric  dozen major i s o l a t e d s e r v i c e a r e a s s u p p l i e d  of r e l a t i v e l y total  B.C. H y d r o ' s  electric  now  small  load  i n the  scheduled centres  p r i m a r i l y by p a p e r , we  scattered  local  will  for  diesel  analyze  only  since  the  i s o l a t e d systems,  t h e 1978 N o r t h - » e s t c o n n e c t i o n ,  will  account  t h a n one p e r c e n t  system  i s  area  of the forecast e l e c t r i c a l  energy  for  less  demand f a c i n g  B.C. H y d r o . Before it  describing  i s important  Just  t o extend  a critical  system  a s i t now e x i s t s ,  distinction  made  earlier.  a s demand f o r e c a s t e r s a r e c a r e f u l t o 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 talk the  the integrated  in  and peak demand r e g u i r e m e n t s ,  planners  t e r m s o f t h e e n e r g y c a p a b i l i t y and p e a k i n g c a p a c i t y o f  s y s t e m . The f o r m e r r e f e r s t o t h e t o t a l  h o u r s t h a t c a n be p r o d u c e d and d e l i v e r e d given  system  time  period.  The  latter  which e n e r g y c a n be g e n e r a t e d  quantity by  describes  the  of kilowattsystem  in  a  t h e maximum r a t e a t  and d i s t r i b u t e d and i s measured i n  kilowatts. As supplied  o f March by  29  31, 1976, B.C. H y d r o ' s  integrated  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  system  was  t h e r m a l and 4  11  gas  turbine  plants  respectively, of t h i s the  capacity  and  i n the  appropriate the  facilities  and  The  usually  It  the  Authority  minimizing  voltage  planned  7  level.  day  6:00  to  needed. The  to  up  the  stepped  at  percent  Station  down  delivered  at  in  the  additional  sub-transmission  to each customer  Hydro  on  sub-stations  load centres  c a r r i e d through  A B.C.  percent,  A l m o s t 50  Shrum G e n e r a t i n g  i s stepped  be  5  map  (Appendix  system  at B)  with . e x i s t i n g  additions.  and  demand  facing  y e a r . The and  l e s s than a.m.  on  attempts within  i s supplied  6:00  p.m.  half that  operate  the  technical  sources are  meet demand d u r i n g  gas  generally  used  i n the  shortfalls  between t o t a l  the  a  e x p e n s i v e gas  its  winter  weekday.  peak, i s  generally  system  in  constraints  As  a i t  demand  rises,  c o n n e c t e d . The are  turbines  (or o i l ) - f i r e d  electrical  varies  meet t h e s e v a r i a t i o n s ,  peak p e r i o d  w i n t e r and  Hydro  costfaces.  hydro-electric projects  hydro-electric  although  To  to  large  on  of the  a holiday.  by  B.C.  s y s t e m ' s a n n u a l peak demand  Peace B i v e r .  natural  and  capacity.  the  hydro-electric  18,  transmission  energy  Shrum p l a n t on  expensive Units  to  electric  fashion  base l o a d the  and  networks  77,  volts  then  o c c u r s between 5:00  reached before  The  is  sub-stations  minimum l e v e l ,  the  500,000  electrical  throughout  electricity  at  distribution  outlines  as  is installed  grid.  transformation  Its  peaking  transmitted  provincial  for  generation  Peace B i v e r . . T h i s  and  the  of  accounting  Burrard  spring energy  more  additional  also  are  such  primarily  occasionally  thermal plant  t o make up demand and  is  anticipated that  which  U n i t s i n g e n e r a t i n g p l a n t s w i l l be c a p i t a l i z e d t h r o u g h o u t t h i s paper t o d i s t i n g u i s h them from t h e more g e n e r a l use o f t h e term.  7  12  can  be  supplied  sometimes fossil  by  performs  fuel  fired  conditions.  In  of t h e energy  to  service  energy produce  on  well  determining  supply.  came from  y e a r , new  capability  the  extent  i t  upon  percent  sources. plants  have  Kootenay  and  Columbia  on  the  Peace  both  power e x p e c t e d  future  expansion  by  and  Pend  B.C.  Hydro  1980.  reguirments,  peak demands i t a n t i c i p a t e s  peak  only a d d i t i o n a l  capacity.  electrical  Some,  energy  been  Rivers.  having  t h e p r o j e c t s i t c o n s i d e r s would add and  the  water  y e a r , o n l y about t e n  thermal  too  t o which  largely  t h e new  and  although  hydro-electric  underway  the energy Most o f  The  8  depends  1975-76 f i s c a l  R i v e r s with  looks at both  sources,  role.  p l a n t s are used  last  Construction i s  In  peaking  generated  into  d*Oreille  a  the  Within the brought  hydro-electric  to  however,  both would  w h i l e o t h e r s add  only  to peaking c a p a c i t y . In both  the p e r i o d to  energy  electric stations of  i n the  Installation planned projects  existing  the of  new  possible. for  Columbia  facilities  R i v e r s and  on t h e  projects and  Island  the  two to  providing are  being  Diversions  meet  Columbia  considered. at e x i s t i n g  main  gas  hydro-  coal-fired  Peace and  generators  represent  addition,  Vancouver  projects  E a s t Kootenay R e g i o n s .  turbines  In  new  s e r i o u s l y contemplated  energy-only  hydro-electric sites  contemplated  major  t h e P e a c e and  Hat C r e e k and  through  are  the  capacity being  p l a n t s on  rivers  Rivers  and  1990,  or  capacity-only  turbine  Units  possible  are  local  Recent federal 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 e x p o r t s generated at B u r r a r d be priced at greater than the equivalent gas e x p o r t p r i c e . T h i s has r e d u c e d e x p o r t s somewhat, a l t h o u g h t h i s h i g h p r i c e s e r v e s as l i t t l e d e t e r r e n t d u r i n g very dry p e r i o d s i n t h e U.S. P a c i f i c N o r t h w e s t . s  13  shortages capacity  pending from t h e  Beyond  considered In  sites  and  selecting  and  them. The the  these  cost  possible  costs  environmental These alternative  various  are  project  generation  and  subsequently  capability  t o the  the  over  the  analyzed  technical  the  are  being  larger  group  explicit  and  projects  over  their  expected  transmission  (including  to  to  to  peak l o a d  T h e s e programmes economic  9  develop  required  e s t a b l i s h e d f o r e n e r g y and  to  legal,  included.  used  programmes  period.  is  resultant least-  already  are then  with  lifetime  according  choices  reference  account  the  these  of  criteria  are to  plan. criterion  i s t h a t the  or g r e a t e r than  costs)  forecast  with  optimal  expensive  Authority associated  adjusted  tentative  requirements  The  dates  c o n s i d e r a t i o n s not  meet the t e c h n i c a l c r i t e r i a  a  d i s c o u n t r a t e s . The  then  or s o c i a l  and/or  Hydro t a k e s  in-service  transmission  using  rankings  establish  B.C.  from  comparative c o s t s o f each o f  calculated,  transmission  sources.  projects  sources,  operating  associated  underwater  less accessible coal deposits  as p o s s i b l e g e n e r a t i o n  of the e a r l i e s t  new  n u c l e a r power, more d i s t a n t  potential electricity  capital  of  mainland.  1990,  hydro-electric  completion  in effect  firm capability  forecast electric  of  f o r determining the  s y s t e m be  energy  equal  e n e r g y demand. F i r m  to  energy  * Although not y e t p a r t o f i t s f o r m a l d e c i s i o n - m a k i n g process, B.C. Hydro has recently completed a detailed benefit-cost analysis employing economic principles. This study (1976c) a t t e m p t s t o h e l p c h o o s e 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 explicitly considering both the quantifiable and nonguantifiable regional and e n v i r o n m e n t a l i m p a c t s i n a d d i t i o n t o the t r a d i t i o n a l d i r e c t c o s t s and benefits of the alternative projects.  14  capability  is essentially  the  total  from  hydro  plants during c r i t i c a l  five  years  of  recorded  operated  at  purchases  made i n a c c o r d a n c e  that  their  stream  actual  (average  energy  flows)  thermal  generation  capability  the  cut  plants  plus the  power extent  critical  capability  is  lowest  thermal  c o n t r a c t s . To  exceed  c o n d i t i o n s i n c r e a s e energy  percent),  plus  energy  with f i r m  conditions  possible  water c o n d i t i o n s (the  maximum a n n u a l  water  production  standard  some  5  back t o r e d u c e  to  10  operating  costs. The  technical criterion  capacity The  reguirements  essence  built  is  now  adopted  the l o s s - o f - l o a d  of t h i s approach i s t h a t  This recently  system  adopted  relatively  more  less  1980's. I t  i n the  reserve  r e p l a c e s one  c a p a c i t y i n the  is  the  probability peak  occurrence  peak c a p a c i t y i s one  criterion  determining  excess  t o t h e p o i n t where t h e p r o b a b l e  demand e x c e e d i n g  for  standard  day  peak  method.  capacity o f system  in  ten  which had  1970's and reguired  is peak  years.  suggested relatively  of  a l l  18  members i n t h e N o r t h w e s t Power P o o l . Having these the  two  determined  technical  basis  of  expenditures original  that  the  criteria,  B.C.  discounted and  capital  discount  the c o s t  operation  intervals  Essentially, return percent)  (and  the  of  Hydro t h e n flow  rates.  expenditures,  theoretically, at  cash  alternative  plant to  programme w i t h  the  i s c h o s e n as t h e  compares  analysis,  The  cash  using  stream  replacement its  and  estimated  highest  economic.  on  nominal includes at  least  subsequent useful  internal  minimum a c c e p t a b l e n o m i n a l most  them  o p e r a t i n g e x p e n s e s and,  equal  a l s o above t h e  programmes meet  life.  rate r a t e of  of 15  15  As  a r e s u l t of  generation combined service Biver  and  transmission  energy dates,  diversion  and  Hat  East  environmentally  Biver  River  generators begin  electricity or in  with  e x i s t i n g or  various  expand  average  projects from  load  the  This  generation in  respectively, appears, level, capacity  plant  1  plant  (1989).  Kootenay  River  McGregor R i v e r  planned one  a  major  suggested i n the  Columbia  (1983), Stage The  legally  Diversion of  to  and/or  to  the  the  Peace  turbines  and  h y d r o - e l e c t r i c s i t e s were year  to  i n t e g r a t i n g the  1990.  Major  e i t h e r with  and  to new  transporting  capacity  system  2  energy-only  Diversion  additions  not  as  comprehensively  projects  meeting  i s u n d o u b t e d l y due and  transmission  1977-1981 p e r i o d ,  of  the  electric  however, t h a t costs  considerations  as one become and  analyzed  transformation  the  capital  Stage  combined e n e r g y and  sub-transmission,  expects,  on  were a s s o c i a t e d  new  with t h e i r  The  a  growth  centres.  Hydro has  facilities. the  and  1990.  Revelstoke,  capacity-only  more s t r o n g l y  B.C.  by  The  i n 1985  coal  to  recommended as s o o n as  (1984) and  at  transmission  were  feasible:  (1985).  projects,  Kootenay c o a l  T a s k F o r c e recommended  through  follows;  Creek  projects  Columbia  plan  capacity  were as  (1981),  (1986), and  t h i s a n a l y s i s , the  to  to  the  and  the  dominant r o l e  require  service's  51  and  capital  the  played  authority 19  percent  budget.  moves f u r t h e r f r o m t h e increasingly  to  distribution  programme which t h e to  need  related  It  generation to  peak  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 the  expansion of  energy c a p a b i l i t y shortages are the  generation  programme u n t i l  clearly the  driving  latter  part  16  of t h e 1980 s.*o H y d r o s e x p l a n a t i o n ,  electric  sources,  specifically available thus  f  h y d r a u l i c energy in  role  debt  sometimes  installed  varying  peaking  stream  u t i l i z a t i o n of  flow  capacity.  conditions,  This surplus i s  as thermal energy s o u r c e s  begin  t o play  a  i n t h e system.  i t s formation,  of  the  compensated  two  the  instruments, balance.  equity  with  capital  i t  sprang,  grants,  a s s i s t a n c e and t r a n s i t from  very  larqely  by  some  i n t h e form  Hiver  Treaty  storage  with  the  service.  After  accounts  for  netting  operation  customers  property  i n service.  The  Authority's  risen  from  large  share  .8  have p a i d  deficit out  approximately  90  t o 4.0 b i l l i o n  for  most  Treaty  percent  of  provided  i n provincial  the  this  B.C.  debt i n t h e form o f d o l l a r s between  result three  to the e l e c t r i c  dams, of  rural  s u b s i d i e s , and have  t o be c h a r g e d  the  outstanding  of this i s held  debt  of  m i n o r a d d i t i o n a l amounts. Funds r e c e i v e d a s a  dams,  and  g e n e r a t e d f u n d s p r o v i d i n g most o f  government  of t h e C o l u m b i a  The distinct  which  financed  internally  contributions  relatively  from  a l l the outstanding  owners o f t h e p r i v a t e c o r p o r a t i o n . I t s  has been  Provincial  electrification  B.C. Hydro a c q u i r e d  organizations  subsequent expansion  1 0  is  f o r hydro-  Financing At  the  under  excess  to disappear  more i m p o r t a n t  2.2.3  capacity  i s that  f o r the purpose of a s s u r i n g t h e f u l l  resulting  expected  generating  forthis  service  Hydro's n e t  bonds  has  1963 and 1976. A  government  trust  funds  system i s described as being ' e n e r g y - c r i t i c a l * (as from ' c a p a c i t y - c r i t i c a l ' ) u n d e r t h e s e circumstances.  17  and  the Canadian  Hydro  is  placement  being and  r a t e on  percent  with  As of the  to  rely  existing  embedded  effective  annual  year  debt  ranges  10  the Province  B.C.  Hydro's s h a r e o f net o u t s t a n d i n g  new  f o r the r e t i r e m e n t o f long  i s s u e s must  amendment sinking are  to  fund  designed  be  stands  approved  the  by  borrowing  payments on to  percent  debt  a t 69 the  ceiling  and  1 1  The  a c q u i r e d o r i s s u e d by  to  will  cover  half  time. securities funds  present, by  Each  1964  the  the  year's an  Act.  five  The  years  principal.  Hydro i s the  the  through  last  refund  l e s s than  1976.  d e b t . At  s e t i n the  debt  which  1/2  sinking  percent.  However, much o f t h e payments  t o 10  in  Legislature  fully  The  guaranteed  i s s u e d within the  approximately  private  issues during  term  debt  B.C.  States.  3 1/4  Act, a l l existing  provided  Columbia  on b o t h  percent f o r the f i r s t  under i t s 1964 by  although  United  from  o f 7.4  are  of B r i t i s h  the  i n t e r e s t c o s t of new  A u t h o r i t y a r e backed  Province  Fund,  increasingly  average  exceeded  established  Investment  i s s u e s i n Canada and  this  an  1975-76 f i s c a l  Plan  forced  public  interest  average  Pension  linked  amount due  at  maturity. B.C. point  where  prevented been  H y d r o ' s n e t income has only  a loss.  providing  a  special  As a r e s u l t , an  Authority's capital  fallen  i n recent years  provincial internally  increasingly requirements.  generated  smaller In the  subsidy  the  last  year  funds  have  percentage  1975-76  to  fiscal  of  the year,  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 g u a r a n t e e d by t h e P r o v i n c e , w i t h t h e i r s h a r e of the total in brackets, a r e : B.C. R a i l w a y Company ( 1 2 ) , B.C. S c h o o l D i s t r i c t s Capital Financing Authority ( 1 2 ) , B.C. Regional Hospital Districts Financing Authority ( 4 ) . The p r o v i n c i a l government i t s e l f has no n e t o u t s t a n d i n g d i r e c t d e b t . 1 1  18  only  10  percent  sources, the  has  In  net  that an  the  s p e c i a l subsidy.  ratio  of debt  attempt t o improve  embarked on  income  t h e s e r e q u i r e m e n t s were met  even a f t e r t h e  fact  95:5.  of  to  a  the  This  reflected  in  to r e t a i n e d e a r n i n g s i s  now  where i t w i l l  B.C.  substantially  Hydro  its  approximate one-third  net  of i t s  interest obligations.  one  The  process  of  of  taking  the  system  f o r e c a s t i n g cash  p l a n n e r s and  obligations.  In  capital  next  them  to  include  five years, its  nominal  dollars  (93  which w i l l  service)  plus  maturities between  and  14  passenger  23  fund  percent  transportation The  Rate B.C.  (depending  be  financial Hydro  5.0  billion  i n the  electric  meet l o n g - t e r m  upon  r a i s e d i n the  the  debt  the  degree  will  be  bond  market.  that of  generated  Setting  rates.  The  Power l e t , a p p l y i n g  Power  Commission, e x p l i c i t l y  schedules s h a l l  the  a p p e a r t o have been  on  remained  of  services subsidies)  direction  be  power"  subsequent  net  by  reguirements. I t a n t i c i p a t e s  b a l a n c e would be  Hydro does not  of  of  system  nominal d o l l a r s to  sinking  and  internally.  2.2.4  percent  billion  basically  f o r example, B.C.  e x p e n d i t u r e s on  .3  is  expenditure f i g u r e s provided  adjusting  the  requirements  estimates c a p i t a l  use  is  i t s credit-worthiness,  programme t o i n c r e a s e  point  from i n t e r n a l  British  silent  on  question  designed  of  the  former  p e r m i t and  Columbia  Columbia this  level  stated that  to  (British  to  the  issue.  Hydro  given or  "the  formal  structure of i t s British  Columbia  Commission's  encourage the  Legislature, and  any  Power  rate  maximum  1960).  The  Authority  Act  19  In  i t s  first  reductions  and  commercial  electric  rate  year,  standardized  was i n t r o d u c e d  addition  of  extension  policy  for  the  both  large  significant  of  Hydro  r a t e s throughout  loads  to  in  the i n i t i a l  which  the  introduction  small  the province.  A bulk  power  the  B.C.  lower  use  rates continued  Two a l l - e l e c t r i c  of  electricity  premises.  and farm paid  uniform electric  a  greater  I n t h e words o f  rates  policies  are designed  of industry  to f a l l  in  to  British  f o r heating  customers  conditioning,  i n each o f t h e next  r a t e s were i n t r o d u c e d  in  home owners t o make g r e a t e r  homes  decorative  1965 use  to  and  became  encourage  small  lighting  electric  the  commercial  available  and was d e s i g n e d of  three  toa l l  t o "encourage  applicances, a i r  and e l e c t r i c  h e a t i n g " . (B.C.  1965,6)  In 1970,  s y s t e m . A new  o f new e x t e n s i o n  power  U n l i m i t e d " o n e - c e n t power"  residential  Hydro,  i n the  (B.C. H y d r o , 1963,6) .  Electric years.  resulting  Hydro  e n c o u r a g e t h e d e v e l o p m e n t and e x p a n s i o n Columbia"  rate  and  costs o f extensions.  of  two  residential  industries,  1963 A n n u a l R e p o r t , " t h e a d o p t i o n  and  introduced  applicable to a l l residential  c u s t o m e r s was i n i t i a t e d proportion  B.C.  1967 e l e c t r i c 1974,  between  1975,  and  10 and 20 p e r c e n t  h i k e s o f more t h a n Annual  r a t e s were  Report  replaced  with  efficient There  1976.  raised, Most  although  50 p e r c e n t  a  of these  between  designed  1974 and  to  repeated  increases  the l a r g e users  i n d i c a t e d t h a t s a l e s promotion programmes  move  ranged  were h i t w i t h  1976. activity  promote  in  the  The  1974  had been wise  and  use o f energy. are  now  essentially  three  basic  customer  rate  20  classes: other  residential,  rate  classes  s m a l l and  they  standard  residential  declining  energy  two  month  all  was  was  the  at  1.7  block. KWH,  cents  general  considered  550  a t 4.6  variety  a  In  1976,  simple  two  kilowatt-hours cents  e a c h . The to  on  (46  minimum  133  KIH  of a l l users  of  use  a residential  the hlock  (KWH)  per  mills)  each  with  charge  for  the  a t the  i n the  yielding  service class  class,  economic  declining  the blocks  per  KWH)  months. The  higher  price,  class  during t h i s  reached two  average p r i c e  month of  of  (starting and  a  an at  5.35  For  the  customers  l a r g e commercial percent  and  2.8  group  vast  a  of  level  of a meter s e p a r a t e l y these  customers  and  falling  was  generally  majority  were  of  four  to  1.5  $8.50 f o r  f o r t h e same c o n s u m p t i o n The  upon  percent  below  minimum c h a r g e o f  of  two  higher  under  the  commercial  group. with  a larger  smaller  In  peak demand, e s s e n t i a l l y  i n d u s t r i a l consumers u s i n g  o f t h e e n e r g y consumed by  tariff i s in effect.  is  90  charge c o n s i s t i n g  cents  for this  within this  1976,  energy  fixed  rate structure.  more t h a n  demand  peak demand. I n  average p r i c e  customers f a l l  s e c t i o n s , depending  installation  what i t would have been  residential  two  peak  f o r the  basis  on  has  peak m o n t h l y demand. F o r  billed  part  users.  energy  and  70  new  Average  measuring energy  the  first  a  s a l e s volume i s r e l a t i v e l y  based  equivalent  the c u s t o m e r s i n t h i s  than  to  although  KHH.  customer's  cents  The  bulk,  their  was  eighty percent  1400  c e n t s per The  rate  charge.  $6.14,  second  period  exist,  p e r i o d were b i l l e d  approximately the  do  and  are often closed  additional  period  general  1976,  the g e n e r a l  class,  peak demand f o r t h e  a  month  over two was  21  billed  on  an  demand i n t h i s The  net  load  factor,  increasing period  effect  increased  four  faced  consumption.  or  75  Total  s i x p a r t energy  energy charge.  o f t h e s e two o p p o s i n g movements, g i v e n a  that  p e r KWH  Average  percent  of  to  generally  p r i c e p e r KWH  f o r either  c u s t o m e r s . The minimum m o n t h l y amount  block rate.  a declining  was f o r t h e p r i c e  g e n e r a l l y below  part  the  fall  for this  residential  peak  with  group  or  was  commercial  c h a r g e was t h e g r e a t e r  the  fixed  of a  demand d u r i n g  fixed  the winter  months. The  third  largest  group  class,  i n terms  l e v e l s of at l e a s t concerns oil  such  bulk customers,  o f a n n u a l energy  60,000 v o l t s ,  as p u l p and p a p e r  r e f i n e r i e s and mines.  notice  55 t o 70 p e r c e n t between  the  next  and  total  month's  i n that  peak  were based annual  sold  T a k i n g power a t  large  industrial  one o r two  plants, year's  average i n c r e a s e s r a n g i n g  197 4 and 1976. R a t e i n c r e a s e s  some  bill.  demand  demand i n any o f t h e was  the  for  10 p e r c e n t a n n u a l l y have been  customers.,  comprises  "ratchet" principle  been  electro-chemical  peak demand c h a r g e f o r b u l k c u s t o m e r s  customer's  energy  mills,  two y e a r s a p p r o x i m a t i n g  currently  that  sales.  they comprise  and f a c e d  from  The  generally  They r e q u i r e e i t h e r  o f a change i n r a t e s  announced f o r t h e s e  have  at  eleven  Peak  two-thirds demand  of  on  the  months.  .3 c e n t s p e r KWH.  Monthly  minimum c h a r g e was b a s e d  to t h e w i n t e r months. The a v e r a g e  use  greater  determined  In  the of peak  1976, a l l  minimum  above,  rate  average  75 p e r c e n t o f t h e h i g h e s t  preceding  on t h e peak demand as  the  calculations  t h e y a r e based and  i s at a f l a t  charges  while  the  on peak demand " r a t c h e t e d "  only  price of electricity  for  this  22  customer c l a s s approximated Other this  smaller  study cover  rate  Hydro  irrigation,  reduced  does  not  determining  assumed t h e  and  now  KWH.  we  shall  those served  o f f e r any  power p r i c i n g  by  not  deal  rooming  with  houses  diesel  in and  generators.  interruptible service,  industrial  r a t e l e v e l s and  following  per  street lighting,  rates, for i t s large  In  cent  c l a s s e s which  areas with s p e c i a l r a t e s B.C.  one  with  customers.  structures,  B.C.  Hydro  has  goal:  To s e l l power t o c u s t o m e r s a t r a t e s b a s e d on c o s t s o f 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 reguired to meet statutory obligations and Government policy d i r e c t i o n s and t o e n s u r e t h e c o n t i n u a n c e o f B.C. Hydro as a financially independent and viable corporate entity. (B. C. H y d r o , 1975b,16) The  Authority  annually and  i n the  reviews  rates  light  i t s projections  reguirements  of  for i t s electric  for capital  expenditures.  f o r t h e s e s e r v i c e s p r i o r t o the ensure that l o s s e s  will  desired  profit  extent  surplus  or  t o which  e x p a n s i o n , and payments  not  within  contained  i n Appendix  in  forecast  operating  results  Rate l e v e l s a r e  years.  Standard  that  The  fiscal  Authority's  historical  cost  with d e p r e c i a t i o n  being  straight  line  basis  g r o s s i n t e r e s t on  debt b e i n g  interest  during  investments.  S a l a r i e s and  net  and  income  i n t e r e s t on  The  on  the  future  most  recent  income i s d e t e r m i n e d ,  followed,  construction  to  net i n t e r e s t  procedures are  and  year  to finance of  set  year.  year depends  percent  which a n n u a l n e t A.  services  funds are  s l a t e d t o r e a c h 30  S t a t e m e n t o f Income, from is  incurred  generated  s i x to eight  gas  commencement o f a f i s c a l  f o r the  internally i s now  be  of  and  from  accounting  c a l c u l a t e d on reduced  sinking  debt each account  a by  fund for  23  approximately services,  30 p e r c e n t  of expenses, followed  costs  Hydro. O p e r a t i n g functions  are  quite  and c a p i t a l  within  finely costs  disaggregated  are assigned  Finally,  each Bate  completely  class  of  levels  the projected  distributed"  annual  methodology  e n e r g y and c a p a c i t y present,  equipment  the  supply  as  the generation  water l i c e n c e f e e s ,  costs  with  result  in  the  to  method,  cover "fully  plus  costs  the  energy  etc.) are  not  associated  electric  transformation generating  categorized with  as  generating  o f t h e a v e r a g e l o a d on which  h a s much o f i t s c o s t  such  as f u e l  approach service  are  attributed  factor  customer c l a s s e s . H i s t o r i c a l l y ,  to  costs  o f l a b o u r and  energy-related. the great  to reduce the share o f costs  used  operating  i s that  helping  is  allocated to the  and a s h a r e  a r e a l s o c l a s s e d as  of t h i s  At  dam, a r e a l l o c a t e d between e n e r g y and  a p e a k i n g p l a n t . Some  level,  a  c o s t s between t h e  transmission,  to i t s c a p a c i t y . Thus a r e s e r v o i r  base-load  The  allocate  generators,  e n e r g y component, u n l i k e at  to  b a s e d on p l a n t f a c t o r , t h e r a t i o  plant  designed  as the c a p i t a l c o s t s o f t h e  c a p a c i t y . The g e n e r a t i o n  capacity  components.  components i s o f f u n d a m e n t a l i m p o r t a n c e .  as w e l l  such  these  i t s share of these  cost accounting  employed  (turbines,  equipment,  service,  surplus.  a l l costs associated  distribution  are  B.C.  various  " c o s t o f s e r v i c e " b a s e d on t h i s  average h i s t o r i c a l  share o f the d e s i r e d The  class  the  and e n e r g y  customers i s given  f o r each  within  to  each s e r v i c e . F o r the e l e c t r i c  c o s t s a r e a l l o c a t e d between t h e c a p a c i t y  and  and  d e p r e c i a t i o n and t a x e s .  These  costs.  by m a t e r i a l s  borne  by  majority  of  to capacity,  the  the commercial  high  load  customers  24  have  generally  borne  customers  somewhat  allocation  procedure.  The above  actual  costs  clearly  impact the  for  each  a l l weigh of  charge.  on t h e r a t e  service"  structure  adjustment  about  the  components  under  this  customers  seem  designed  to  to  increases,  1976  fell  block  rate  placed  the  to  those  Bulk r a t e and  on t h e i n i t i a l  under  in to  an  bulk  result  customers,  with  their  energy  c h a r g e d o u b l e t o .6  peak  demand c h a r g e i n c r e a s e s  f a c e an i n c r e a s e d  tailing  from  energy  their  charqe  their  declining  or f i x e d with  costs  tailing  costs. emphasis  Thus b u l k u s e r s w i l l  Residential  c e n t s p e r KWH  in  users. For  cents i n 2 years , while  b l o c k o f 2.0  two  charges as  an i n c r e a s e d  only marginally.  an  industrial  users  i n c r e a s e d share of the energy  an  demand  capacity  minimum c h a r g e ,  component o f t h e b i l l .  with  these  Smaller  to  service"  peak  twice that of the l a r g e  r a t e h i k e s seem t o i n d i c a t e  energy  political  of  between  and  the  the  as  stability,  the "cost  scheme.  energy  b l o c k and  t o be  peak demand, f a c e  although the marginal  and c o m m e r c i a l  the  customers,  e n e r g y c h a r g e s , much o f t h e c a p a c i t y  1977  recover  not appear  appear  of  this  maker's mind i n a d d i t i o n  imbalance  their  below a l m o s t  blocks r e f l e c t i n g The  would  allocation  approach  residential  does  reduction  extreme  have  consumption never  residential  r a t e o f c h a n g e and  information.  corresponding  This  the  s h a r e o f c o s t s b a s e d on  class  permissible  heavily  a  and  p r o c e s s . C o n s i d e r a t i o n s of revenue  uneasiness  on  rate  charge twice that c a l c u l a t e d  method, w i t h  are  of t h e i r  s e p a r a t e f l a t charges f o r energy  energy  the  more,  customer  structures,  "cost  their  less  d e s i g n o f the  a defined  future cost  somewhat  see  their users  although  a  25  new  $ 3 . 0 0 e a c h two-month p e r i o d  s e r v i c e charge of  biggest  i m p a c t on  evident  in  small  the  introduction  users.  increase  more f o r the  These r a t e s t r u c t u r e i n t e n t i o n of  while  raising  expenses. claimed upon  that  use  rate  a  smaller  changes r e f l e c t  initial  recent  energy  charge  1977).  (Bonner,  this  the He  would  went  energy  have t o be  charge  would  would p l a c e  neutral  on  the  r a t e " would  a d j u s t m e n t s would aim i n c e n t i v e and  about  Hydro's  longer  to  fixed  C h a i r m a n o f B.C.  Hydro  neutral in their effect separate  to  say  and the  a  flat  customer's  that,  if  fully  a s e r v i c e c o s t component per  added.  1 2  month  to  Because o f  user,  he  stated  probably  never  be  a c h i e v e d , but  at  consumption cover  small  further  d i s i n c e n t i v e to  chapter  b a c k g r o u n d on  rate  that  which the  "ideal  that as  an  burden  this  neutrality  (for  future between  use. ,  B.C.  determination  has  attempted  Hydro t o p r o c e e d and  to  present  w i t h an  implications  * I f t h e r e v e n u e r e g u i r e m e n t f o r the be met, t h i s would i m p l y a f l a t e n e r g y KWH b a s e d on 1976 figures., 2  raising  Summary This  the  be  $8.65  of  2.3  the  on  involve  the  again  s e c o n d component o f  r e s i d e n t i a l customers)  this  restructuring  f o r energy  designed  rates should  u s e d as  the  service class i s  B.C.  rates  statement,  "electrical  implemented,  rate  have  accounts.  with s e r v i c e c h a r g e s c o m p l e t e l y  for  bill"  general  " f l a t t e n i n g " the  the  In  f o r the  only  a monthly s e r v i c e charge of $ 2 . 2 5 ,  of  costs r e l a t i v e l y  term  The  will  of  the  necessary  economic a n a l y s i s an  appropriate  of  rate  r e s i d e n t i a l c l a s s were t o charge o f 1.0 cents per  26  structure  f o r the Authority.  framework w i t h i n the  past  and p r e s e n t  essence o f the  is  as f o l l o w s .  met by t h e A u t h o r i t y .  and  demand.  The s y s t e m  environmental The  necessary  necessary rate an  attempt  funds.  plan  entail Finally,  linkage  explicit.  The  connection  i s not.  to  meet  advised  the rates  between  B.C.  produces a be  to certain technical, this of  and c a l c u l a t e s how  meet f a i r l y  The  section  at  group d e s i g n s a l e a s t -  suhject  is  process  and peak demand t o  planning  team  Authority.  forecasting  forecasting  l e v e l s and s t r u c t u r e to  planning  constraints  financial  reguirements t h i s w i l l  in  on  p o l i c i e s i n key a r e a s o f t h e  o f expected energy  e x p a n s i o n and o p e r a t i n g  legal  the  electrical  T h e demand  10 t o 15 y e a r f o r e c a s t  cost  focussed  service.  The Hydro  the i n s t i t u t i o n a l  which B.C. H y d r o o p e r a t e s and has  Authority's  electric  I t has d i s c u s s e d  the  best  department  forecast capital  to  raise  p r o j e c t s the  f o r each c l a s s of  customers  the revenue reguirements o f the each  of  these  functions  between t h e r a t e s t r u c t u r e  is  and demand  27  3.. THEORY AND  3.1  Emergence Of The Economic  monopolist would  be  by  discrimination  addition,  that  produce  a  aggregate  were  associated  of  the  capital-intensive  were  carefully  watched  profits.  The  the r e s u l t i n g the was  case  of  be  throuqh  into  then  price  s e c t o r s with price.  average  the In  submarket price  inherent most p u b l i c  monopoly  they  d i d not  so  formal  utilities Electric  position, make  their  but  were  unwarranted  became t o e n s u r e  were a d e q u a t e b u t electric  in  monopolies".  focus of r a t e s e t t i n g revenues  divided  w i t h i n each  scale  "natural  that  the  highest  below  revenue,  some o f t h e c o n s u m e r s u r p l u s  of  this  privately-owned  o f t e n determined  the  processes,  of  to ensure  total  would  demand c u r v e s .  economies  assured  primary  than  for  elasticities,  price  were c o n s i d e r e d t o be s o - c a l l e d utilities  more,  demand  whereby t h o s e  could capture  production  the  structures  w i t h downward s l o p i n g  Because  charge  production  of  charged  with marginal  monopolist  and  maximizing  market c o u l d be  price  where p o s s i b l e , r a t e  the  profit  less,  function  attempted  demand  designed  a  Aggregate  different  would be  inelastic  that  marginal cost equal t o marginal  being  with  MARGINAL COST PRICING  M. C.P.  optimal.  I f the product's  submarkets  would be  to  setting  price  Of  suggests  tend  socially  with s e l l i n g product.  Theory  theory  would  determined  most  METHODOLOGY OF  that  not e x c e s s i v e . I n  utilities, regulation  this based  adequacy on  an  28  approved  rate  of r e t u r n  publically-owned less formal  financial In  involved egual  viability  designing  revenue  to of  that  the  s e r v i c e " of  clearly below  the  defined,  average  in  a d e c l i n i n g block  class.  The  "value  limit  on  price,  elasticity  of  the  long  demand  f o r example, w i t h  discrimination use  increased,  both  expanded  use  to b e n e f i t  that  a l l by  i n the  such  leading  term  that  prices  cost"  and  Although  and  long  within  intended  an  total  inverse The  each  to  low  and  "value  usually  of  set  l e d to l o w e r  customer  as  lower  average  thus  upper the  industrial available  prices  price for  generally  a  consumption  classes.  costs,  to  customer  s e r v i c e " . Thus  rate s t r u c t u r e s encouraged to  held  an  large  electricity  between  never  measure o f  combined r e s u l t was  for  the  run,  a l t e r n a t i v e sources of energy  price  within  believed  short  electricity.  c u s t o m e r c l a s s e s . The average  was  this  were g e n e r a l l y  rate structure  between c l a s s e s  declining  costs"  essentially for  with  1  both the  them, were s a i d t o have a  prices,  to a s s u r e the  load. *  s e r v i c e " concept,  was  usually  income  "incremental  "incremental  costs  of  was  For  1 3  accounting  consistent  incremental  suggesting  higher  net  rate base.  process  objective, practitioners generally  of  to  the  reguired  rate structures  "value  users,  that  cost  utility.  l i e somewhere between  be  historical  ensuring  should  very  an  o r Crown c o r p o r a t i o n s ,  and  approximately  on  was  The  designed  and  hence  future.  Considerable discussion in the economic literature has c e n t r e d a r o u n d t h e q u e s t i o n of t h e p o s s i b l e d i s t o r t i o n s i n the relative i n t e n s i t y of use of various 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 f r o m t h e 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). See, f o r example, t h e p r a c t i c a l g u i d e t o t h e a r t o f e l e c t r i c r a t e making by Caywood ( 1 9 5 6 ) . 1 3  1 4  29  Micro-economic for  the  theory  maximization  tells  benefit  from  product  i s egual  t o the  the  production  marginal  I f i t i s assumed t h a t  represents  marginal  efficiency egual will  be  able  relative the  implies  cost  most  this  situation,  supply  side  marginal  p r i c e of 1 5  will  in  be  externalities of  pattern  the  a  do  formulation,  on  costs  The utility the  and  then  we  of  i n d u s t r y , the  impossible  l e d to  and  should  response while  are will  competitive  either  curve  the  to at  being act  to  market monopoly.  demand  or  must r e s o r t t o  the  employing  marginal  benefits.  presence  past,  forces  that  a consumer  presence of a  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 social  in  a  economic  a product  resources  perfectly  exist  for  satisfaction  economic  l a c k i n g i n the  from  social  In t h i s way,  that society's scarce Natural  marginal  demand  marginal  condition  a s t o m a x i m i z e h i s own  condition  but  i n fact,  that  this  of p r o d u c t i o n .  efficiently.  the  individual's  t o a d j u s t h i s consumption  p r i c e s so  satisfy  If,  t h a t the  same t i m e e n s u r e  used  then  i s that  condition  cost resulting  s o c i a l b e n e f i t and equal,  i t s marginal  an  a necessary  o f an a d d i t i o n a l u n i t o f  social  production.  are  that  of s o c i e t y ' s w e l f a r e  social  private costs  us  what  a  t e c h n i c a l e x t e r n a l i t y i n the  electric  i n c r e a s i n g returns to s c a l e experienced seemed  dilemma i n d e s i g n i n g  to an  some  economists  optimal  to  be  in an  r a t e s t r u c t u r e . With  T h i s d i s c u s s i o n d e a l s o n l y w i t h e c o n o m i c e f f i c i e n c y - how to allocate resources so t h a t t h e y c a n n o t be f u r t h e r a d j u s t e d t o i n c r e a s e s a t i s f a c t i o n w i t h o u t making a t least one party less satisfied and ignores t h e 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 . I n o r d e r t o d e r i v e an o p t i m a l s o c i a l welfare position which includes considerations of both efficiency 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 . 1 S  30  marginal  c o s t s below a v e r a g e c o s t s , t h e e g u a t i n g  of p r i c e s  marginal  c o s t s would n o t meet t h e t o t a l  reguirement.  In  1938,  Hotelling  t h e o r y by a d v o c a t i n g  startled  that  the  revenue  the  world  economic  of u t i l i t y  efficiency  become  t h e 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 .  equated  with  short run marginal  would be s u p p l i e d f r o m debate over  this  practitioners tending  rejecting  the l a s t  interest  i n the  applied  to  have a l t e r e d social  in  scheme  marginal  resource  of  and  marginal  the  issue  recognized  of  next  years,  and  15  academic  cost  as  basis  for  particularly  the  rising  electricity  that marginal  costs  divergence  sufficiency  private  and  generation  and  exceed  that i t i s  the  f o r optimal  both  short  between  criteria  as  of the debate  real  the  average decades economic  c a n be r e c o n c i l e d  marginal  price  that  must  resource  allocation.  Hence  price  can  theoretically  be  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 . vs. long  t h a t i n an o p t i m a l s y s t e m  run  marginal  c o s t , i t was  t h e two a r e i d e n t i c a l  I t s h o u l d be r e c o g n i z e d t h a t t h e t o t a l r e v e n u e i n an e c o n o m i c s e n s e have no n e c e s s a r y r e l a t i o n s h i p r e q u i r e m e n t s u n d e r an an h i s t o r i c a l c o s t a c c o u n t i n g 1 6  with  economists  the  The c i r c u m s t a n c e s  adjustments i n t h e i n t r a - m a r g i n a l  On  Considerable  Some o f t h e i s s u e s o f t h e e a r l i e r  revenue  made which w i l l e n a b l e  revenues.  structures,  with  apparent  cost  shortfalls  allocation.  rate  utilities.  now s u g g e s t i n g  many c a s e s .  criterion  decade t h e r e h a s been c o n s i d e r a b l e renewed  associated  when i t i s r e a l i z e d equal  run  f o r the  d r a m a t i c a l l y , with  were r e s o l v e d . The efficiency  the  theory  electric  costs  distribution costs  long  an o p t i m a l  Within  government  rate  P r i c e s would be  c o s t , and any r e v e n u e  p r o p o s a l ensued  t o favour  determining  general  with  once  requirements t o revenue framework.  the  marginal c o s t s  costs.  For  1 7  using  the  non-optimal present  change e f f e c t i v e l y social  of c u r t a i l m e n t  time  are  included  systems, Turvey's  value  of  u s e s an  the  of  short  run  (1968) s u g g e s t i o n  of  change i n c o s t s  average  preference)  i n the  (weighted  both  short  by  f o r a demand the  and  long  use  of  rate  run  of  marginal  costs. A commonly pricing the  in  when  of  at  theory can  introducing least  efficient that  This  conclusion  welfare  argument  one  be  other  should  costs  are  for the  when  transferring  still  substitute do  not  as  The  does not  standard  determine  this  to  the  pricing  what  partial  in use  one an  to  a  no  on  this  general  perspective  of *a  social  industry  economically  relevant  marginal  cost  theory  that  impact  reply to the  the  argument marginal  under c o n s i d e r a t i o n .  industry's  economic e f f i c i e n c y  o r complement  satisfy  states  drawn  framework, a d j u s t m e n t s i n t h a t d e s i r a b l e f r o m an  essentially  industry  a  marginal  around  particular industry from  the  revolves  marginal cost  pricing criterion.  one  against  a particular industry  second best.  priori*  is  heard  Then,  eguilibrium  p r i c e s may  be  i f significant  p r o d u c t s e x i s t whose p r i c i n g  practices  criterion.  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 costs incurred by society as a r e s u l t o f a s h o r t a g e o f e l e c t r i c i t y . For an o p t i m a l l y d e s i g n e d s y s t e m , marginal social curtailment cost should equal marginal social cost of adding e l e c t r i c a l supply c a p a c i t y . 1 7  32  3.2 Emergence Of The Methodology find A p p l i c a t i o n Of M.C..P. although  the  basic  marginal c o s t  pricing  circles,  application  the  theory  is  now  establishing well  of  the  established  this  theory  to  reject  design.  costs,  and  much l e s s  that  has l e d  debate over s h o r t  vs. long  run  the r e c o n c i l i a t i o n o f economic e f f i c i e n c y  revenue s u f f i c i e n c y , the  witnessed  economic  1 8  In a d d i t i o n to the general  and  of  the economic e f f i c i e n c y o b j e c t i v e as a c e n t r a l  c r i t e r i o n i n rate  marginal  in  remains  developed. Indeed, i t i s t h i s apparent d i f f i c u l t y some  merits  considerable  electric  utility  controversy  over  literature  the  marginal energy and c a p a c i t y c o s t s . T h i s has  has  allocation  manifested  of  itself  i n d i s c u s s i o n s on "peak load p r i c i n g " and the r e l a t e d problem o f the " s h i f t i n g The  peak".  basic  prevailing  charge both marginal during only  the  allocated  operating  system's  marginal to  peak  operating peak  approach  by economists today i s t o  and  capacity  costs  p e r i o d s , with off-peak costs.  periods  1 9  since  Capacity  are  periods  represents  "sunk  c o s t s " with an  cost of z e r o . I f t h e r e are s i g n i f i c a n t costs  within  either  of  these  s t r u c t u r e d r a t e schedule can be devised variations.  Moreover,  to  the  extent  s t r u c t u r e would be expected t o lead  1 8 1 9  variations  periods,  to  then  fully  t h i s demand t h a t  prompts new investment. The investment i n eguipment i d l e off-peak  users  users f a c i n g  costs  i t i s only  to  during  opportunity in  a  t o correspond  marginal  more f i n e l y to  these  that the r e s u l t i n g r a t e shifts  See, f o r example, Lewis (1949). See, f o r example, B e r l i n (1974) and Joskow  in  (1976).  the  demand  33  p a t t e r n , adjustments i n the r a t e s t r u c t u r e would have t o be made i n a n t i c i p a t i o n of these movements. The  first  real  attempt  to  apply  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 France  (EDF)  hydro  and  and  thermal p l a n t s . The  way  and  key  to  The  be  future  of  an  demand.  EDF  optimal  with the  those  Curtailment  the  from  it  when  by  costs the  present  costs  line  load.  work, other  their  the  l o s s e s plus the c a p i t a l carried  costs  level  utilities and  a  full  r e s u l t i n g r a t e s were  major customers.  were o f f e r e d to the  this  costs  l o c a t i o n and  of  assumed  in  marginal  voltage  analysis  changes  the e f f e c t i v e o p e r a t i n g  c o s t s were a l s o estimated. The  t h i s pioneering  expansion  tracing  were imputed. The  the  the  c o s t s were determined from  l i n e flows,  were the o p e r a t i n g periods  of the  d i f f e r e n t i a t e d by time, season,  economic  that  proceeded to c a l c u l a t e  c o s t s o f thermal p l a n t s and,  of t r a n s m i s s i o n  Since  production  recognized  analysis,  generation  f o r the hydro f a c i l i t i e s  during  appropriately  system with short run marginal  anticipated transmission  costs  of  found the a p p l i c a t i o n o f  To s i m p l i f y the  run c o s t s . Marginal  the o p e r a t i n g and  that  reoptimization  equal to long run marginal c o s t s and short  comprised  problem i n undertaking a  utility  with the  de  a n a t i o n a l i z e d power  of the system t h a t would r e s u l t  approach d i f f i c u l t . existence  Electricite  to c a l c u l a t e marginal c o s t s would be t o compare  operation  present  seen  power.  cost changes a s s o c i a t e d and  was  the heavy f i x e d c o s t s a s s o c i a t e d  d i s t r i b u t i o n of  correct  of  most of France with a system evenly  marginal cost a n a l y s i s was allocating  that  i n the e a r l y 1950*s. EDF  company s u p p l y i n g of  is  marginal c o s t p r i c i n g  and  geographic  have undertaken  have implemented  rates  34  based, i n varying This  approach  number  of  of  i s gaining  regulatory  utilities One  under  the  electricity  (1976).  upon  marginal to  based  on  EDF, the  and  of  pricing  the  Ontario  parts of  the  electric  peaking  allocated real then being  Hydro  expenditures  on  to  States  ordered  move i n t h i s economic  that new  not  which  to  be  the  rate  analyses  the  involve  a  and  are  d e t e r m i n e d by  transmission  those  broadly  times with  the  is 2 2  methodology but  rather certain  of  costs  costs a  future  These c o s t s  periods greatest  with loss  gas  are a l l  annualizing  facilities. defined  U.S.  capacity  costs  transmission  based  costs  analyzing  generation  of  methodology  marginal  develop  0  Ontario  structures  and  annualized  Marginal  electric  direction.?  most common i n the  does  where a  u n d e r t a k e n by  relevant  system.,Marginal  d i v i d e d among v a r i o u s allocated  was  principles.  of m a r g i n a l c o s t e s t i m a t i o n ,  plant.  to c a p a c i t y  United  principles,  a p p r o a c h now  "shortcuts"  e s s e n t i a l l y taken  turbine  the  pure t h e o r y  various  to  thorough  pricing  pricing  recently  s t u d y recommended  cost  employs  are  and  determine  representative Like  The  2 1  have  jurisdiction  recent  costing  marginal cost  acceptance i n the boards  their  more  Hydro  employed  d e g r e e s , on  of  are most load  See, f o r e x a m p l e . Public Service Commission of Wisconsin (1974) and S t a t e o f New Y o r k , P u b l i c S e r v i c e C o m m i s s i o n ( 1 9 7 6 ) . a l t h o u g h t h e B o a r d of D i r e c t o r s o f O n t a r i o Hydro has f o r m a l l y accepted the underlying principle that efficiency in the allocation and use o f r e s o u r c e s i n p r o d u c i n g e l e c t r i c e n e r g y i s t h e 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 t a k e n any p o s i t i o n on t h e s p e c i f i c r e c o m m e n d a t i o n s o f t h e s t u d y . One reason for this i s that 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 e c o n o m i c c o n s u l t i n g f i r m , u n d e r t o o k much o f t h e m a r g i n a l 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. It has p e r f o r m e d s i m i l a r work f o r many o f t h e e l e c t r i c u t i l i t i e s i n t h e U n i t e d S t a t e s now g o i n g t h r o u g h t h i s p r o c e s s . C i c c h e t t i * s (1976) manual on marginal cost pricing advocates the same basic approach. 2  0  2 1  2  2  35  probability.  Marginal  average  the  energy those  of  by  explicitly which  a  be  basis  of  for  for  metering,  33  B.C. as  a  stated  in  has  no  enough  M, C. P.  has  used  user revenue 2 3  of  Units  of  rate  revenue  weighted with  A l l costs  are  estimates  demand  capacity  a  associated  are  pattern  change. costs  are  not  shifts  These  structure,  time-  then  used  appropriately  constraints,  by  prime  are,  This  formally  and  fully B.C. with  role  classes to  Methodology  For  B..C._  adopted  setting policy. It  current  Its  objective.  optimal  be  periods.  this and  to  initial  result  from  never  i t s rates  relationship  approach. various  An  i t s rate  The  methodology  cost  these  a  energy  s e t t i n g an  taken  different  and  as  marginal  are  eguity,  cost  etc.  that  "costs".  Hydro  expected  Hydro  goal  these  considerations  Developing  T  costs  variable  recalculated  would  adjusted  during  Ontario  differentiated as  highest  production faced  energy  enable  an  the  somewhat  economic  has,  to  determine  appropriate  to  that  Authority  to  be,  average "cost  of  marginal  allocate accounting  ensure  efficiency  however,  continue  distributed  Hydro  i s to to  should  Hydro  costs  each  class  meet  i t s  publicly based  on  costing service" costing amongst  contributes net  a r b i t r a r y , backward-looking  income approach  T h e c h o i c e o f a l l o c a t i o n m e t h o d h a s an i m p o r t a n t i n f l u e n c e o n the r e l a t i v e share of t o t a l c o s t s a t t r i b u t e d to each c l a s s . Thus the B.C. Hydro method, with i t s heavy a l l o c a t i o n of c o s t s to capacity, favours the high load f a c t o r c l a s s e s (industrial) at 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 (residential). 2  3  36  is  then used  average  as a b a s i s  rates.  It  prices consistent  fails  some  i t  economic  perspective.  ignored,  and  charge adjusted costs  Thus  from  "cost  below t h e i r cases,  between e n e r g y  plant  rather  from an  at their  cost  t o the u t i l i t y  true  opportunity  are  cost  in  inflation historical  of  cost  and c a p a c i t y  and  differing  cost  depreciation  and i t s i n f l a t i o n nominal  service"  interest  methodology  are  buried  by  the  cost.  a l l o c a t i o n i s done i n  responsibilities i s on t h e  basis  since  an  a r e l o s t . The of  existing  a l l costs  Time-  a r e lumped  manner end  costing in  loading"  which of  methodology i t is the  are  further  applied  i n rate  fixed  charges  and c o m m e r c i a l c u s t o m e r s r e s u l t s i n m a r g i n a l  r a t e s below even  are  averaged.  The " f r o n t  cost  a  Authority  m a r g i n a l nominal  These weaknesses i n t h e  average  in  the  B.C. H y d r o ' s c o s t  costs  and t h e n  residential  criterion  t h a n on t h e c a u s e o f b u i l d i n g new f a c i l i t i e s .  differentiated  setting.  as  forsetting  wrong c o s t s  S i m i l a r l y , t h e average  way and i m p o r t a n t  intensified  basis  well  to  their  average  the  split  together  are valued  the  in  other  arbitrary  the  external  subsequent  average l e v e l .  substantially In  uses  below b o t h i t s own m a r g i n a l l e v e l  used  as  Commitments made a t d i f f e r e n t t i m e s a r e compared  despite  is  simply  significantly  technologies.  an a p p r o p r i a t e  Costs  resources  some i n s t a n c e s . directly  as  marginal  ways.  cases  which d i f f e r s  determining  with t h e economic e f f i c i e n c y  number o f f u n d a m e n t a l In  for  the costs  method.  demand c h a r g e s a r e b a s e d  d e t e r m i n e d on t h e  fully  energy  distributed  F o r t h e l a r g e r c u s t o m e r s , t h e heavy p r i m a r i l y on t h e i n d i v i d u a l  for  peak  customer's  37  demand  pattern  otherwise  with  with t h a t  of the  Unfortunately, determine of  these  marginal  the  relevant  which  significant intensive operating  respects.  assume  electrical  system  in  the  direction  of the  its  that  appear,  for  B.C.  and  growing  The  The  nature o f the system.  which  not  coincidence  have  been  in  other  is  the  relates  to  existence i s both  marginal demand  of  energy  costs  an and  variation.  costing  two  marginal  technigues  economically  optimal  of the s i z e  assumptions  thus  y i e l d a good  of  costs.  are  certainly  may  and and be  approximation  not  valid  for  Hydro. The  economic currently  B.C. sense  Hydro that  system the  i s not  short  above t h e l o n g r u n  hydro-electric  projects  than  the g a s - f i r e d  its  opportunity cost).  operating  in  the  curve  is  c o s t curve, because o f  the  run  price  average  cost  of petroleum.  are e s t i m a t e d t o produce  Burrard thermal  plant  Thus t o r e l y  c o s t s o f B u r r a r d as t h e  would o v e r e s t i m a t e  o p t i m a l l y designed,  average  p o s t - 1 9 7 3 major i n c r e a s e s i n t h e  rate  from  capital-  capacity-critical  These  be  energy-critical  f o r some s y s t e m s and  B.C.  in  extremely  are independent  However, t h e y  to  systems  the  to  generation  w i t h c o n s e g u e n t i a l l y low  Most c u r r e n t m a r g i n a l  that  or  have some  case,  hydro-electric  from  first  second  the  any  reasonable marginal  used  H y d r o . T h i s stems i n p a r t  i t  of the system  costs.  implicitly  technigues  distinguishes  nature  for  system.  do  Hydro's v e r y l a r g e  base,  regard  costs f o r other e l e c t r i c u t i l i t i e s  w e a k n e s s e s and  particularly B.C.  little  these  appropriate  costs.  cheaper  (when gas  exclusively  Hence  on  energy  i s priced the  marginal  new  at  marginal energy  38  The  fact  that  t h e B.C. Hydro s y s t e m  e n e r g y and c a p a c i t y - c r i t i c a l a l s o New but  generating that  projects  allocated  solely  associated  transmission  and  centre,  to  the current  projects  should the  in  marginal c o s t i n g  the  will  The  false  third of  the  to  evident  because  technical As current  too with the  project  the "cost  these  cost  concerns costs  of the  to  to  in  Burrard  and  should  Hydro  or  the  linearity  demand  will  then  spilling  of  society.  Other  indivisibilities  and  changes. F o r  will  generally  first  be  plant. met  by  water o v e r dams  very  little  cost  non-linearities will and  be  rates.  decrease by  the  capacity-only  use o f t h e e x p e n s i v e B u r r a r d t h e r m a l annual  the  of s e r v i c e "  changes  ( a s s u m i n g no e x p o r t m a r k e t i s a v a i l a b l e ) , w i t h savings  changes  m e t h o d o l o g i e s . Changes  assumption  However, a s u b s t a n t i a l down  new  i n s e t t i n g today's  of  cost  So  i n t h e a n n u a l e n e r g y demand  increased  shutting  but  response  an i n c r e a s e  to  component.  a f f e c t the timing  1980*s,  discounted  example,  have t h e r e s u l t a n t  energy  capacity,  because of changes i n t h e  l i n e s l i n k i n g the  appropriately  symmetry  only  both  implications.  p r o d u c e both e n e r g y and  a procedure c o u n t e r t o both  peak demand f o r e c a s t  lead  has i n t e r e s t i n g  a r e advanced or r e t a r d e d  e n e r g y demand f o r e c a s t ,  load  that  i s not c u r r e n t l y  somewhat  be  arbitrary  criteria. * 2  a r e s u l t o f t h e s e and o t h e r marginal cost  important  weaknesses i n t h e  p r i c i n g methodology, a d i f f e r e n t  approach  * F o r example, t h e t e c h n i c a l e n e r g y o r 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 in anticipated demand to automatically t r i g g e r t h e advancement o f a p r o j e c t by a f u l l y e a r . An e c o n o m i c analysis 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 t h e i n c r e a s e d r i s k s o f an e l e c t r i c i t y s h o r t a g e than incurring the e x t r a r e a l c o s t s o f a d v a n c i n g t h e p r o j e c t by a y e a r . 2  39  is  reguired.  The  outlined  by EDF  (1968).  I t  cost  in a  or  revolves  costs  future  B.C. to  we  Hydro's various  demand  adjust  cost  itself cost  load  marginal  and c a p a c i t y  costs  r e s u l t i n g from peak  totally  in  associated All in  real  with  costs  equal,  used  than  nominal  cost  due  project,  i n terms  the will  1976  i t s real  of  the  operate  way,  subject  electrical  will  then  value  same  falls  the  o f the  altering  i n  demand,  between the  the  additional  p a r t l y on the  increase the  of  marginal  By  allocated  be  system  value  change  yield  analysis  project  to inflation.  and  the change.  that  dollars.  cost  present  simulation  today's  example,  of  occurring  marginal  costs  demand.  economic  of a construction  not affect  For  i n peak  i n this  using  yield  increase  periods  a change  terms  commencement  rather  off-peak  will  value  a given  the present  hypothetical  components.  period  by  marginal  of the e l e c t r i c  be a p p r o p r i a t e l y  a demand  plan  present  r e s u l t i n g from  can  of  computer  forecast  The  divided  factor of this cost  upon  and d e s i g n  of kilowatt-hours  energy  system's  based  Turvey  i n the  i n a cost-minimizing  i n t h e demand  difference  will  i s that  by  meaning  change  using  which  accordingly.  kilowatt-hour  system  the  system  the operation  quantity  per  a marginal  a model  adopt  i n the present  electricity.  A change  and  associated  the  integrated  forecast.  changed  with  build  will  and c l a r i f i e d  - t h e change  for  we  the fundamental  technical constraints,  introduced will  around  associated  shall  that  reformulated  context  demand  technigues,  method  and l a t e r  dynamic  society's  basic  A  be  one y e a r  will,  despite  will  a  delay  i n the  a l l things  being  likely  increase  I t i s the r e l a t i v e  foreqone  expressed  alternative  cost  uses  i n i t s of the  of  the  40  resources delay  will,  project of  employed,  a l l things being  to society  future  real  c o s t s we  society  would  resources already  made  will  be  not  operating  are  are  value  increase  (decrease).  will  deviate  B.C.  Hydro.  cost. than  2 6  be  "sunk in  this  which  The  assumed  will  what B.C.  zero  the  discounting by  society's  we  attach  be  to  be  This i s p a r t i c u l a r l y  at  p r i c e are not  being  that  rise  upon  valued  at  to  in  at  their its  fitting fulfilled  s i n c e gas  cost  and  variable  by  operating  opportunity price,  more  i n i t s thermal  export  because o f  analysis  measured  full  gas  The  meet a demand this  export  pays t o b u r n  the  here.  a l l the A u t h o r i t y ' s  priced  had  have a p o s i t i v e  (fall) used  the  ways from c o s t s a s  fuel,  H y d r o now  is  what  investments  opportunity  focussed  economic c o s t s  of  costs -  Those  It  costs  costs w i l l  t o be  will  uses.  analysis.  investment  exception  gas  premium  year  of  h e n c e must f o r e g o ,  c o s t s " with  plants. this  and  i n s e v e r a l important  the  t o the  discounted  the  alternative  of these  Natural  twice  to  and  present  costs w i l l  received,  future  cost  due  cost  i n t e r e s t e d i n are opportunity  included  opportunity  be  the  t h e one  consumption.  put  and  With  today)  time preference,  have  been  in fact,  2 5  reduce  c o s t s . These c o s t s s h o u l d  over f u t u r e  The  equal,  (as viewed f r o m  r a t e of s o c i a l  present  that i s important.  contracts  upstream  demand  To the e x t e n t t h a t "money i l l u s i o n " e x i s t s , t h e r e a l c o s t s may, i n f a c t , vary because of inflation. It is difficult to determine 'a priori' t h e net e f f e c t o f 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 c a s e s (eg. c o s t of capital) and l o w e r i t i n o t h e r s (eg. c o s t o f l a b o u r ) . To the extent that resources used by B.C. Hydro would o t h e r w i s e be u n d e r e m p l o y e d , t h i s a s s u m p t i o n overestimates true opportunity c o s t s . An o b v i o u s 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 h i g h unemployment a r e a .  2  5  2  6  41  in  British  B.C.  Columbia.  deposits  could  be v a l u e d  have r e c e i v e d  implicitly river  will  to  of past  cost  planning  the  cost  relative  selecting least  project  expensive  proceed  externalities  associated  Depreciation  life  have gone  estimate  a l l . These e s t i m a t e s reduce  with  charges  not  will  costs  from  Although  decide  of  have  insulation,  ensured  other  cost of  whether will  the  include  the  negative  based  on  the l i f e  being  of the  t h a n on  depreciated.  2 8  the Had  equipment lives  modernization  of the c a p i t a l  or  i n these  a f a s t e r repayment and s u b s e q u e n t  resources  depreciation  when  i n a dam, f o r example, i t c o u l d  would  line  to  some  ie  projects  with  adjusted  the projects.  been i n v e s t e d  home  be  of the  the absolute  at to  i t  will  cost  to actual cost.  reguired  d e v e l o p m e n t . The s h o r t e r  Straight  real  i s  petroleum  combination  in  n o n r e s i d e n t i a l investment, rather  into  that  be a p p r o p r i a t e l y  changes  of the p a r t i c u l a r asset  capital  price  opportunity  t o proceed with,  one  reguired  expected  net  from  2 7  will  with  to final  project  average Canadian  c o a l production  o f each p r o j e c t i s a l l t h a t i s important  which  should  the  project.  estimates  expenditures  the  represent  experience  preliminary  the  a t the highest  a f f e c t e d by t h e power  light  future  elsewhere. Annual water l i c e n c e f e e s  assumed  Construction in  Similarly,  to  raise  social  over t h e "opportunity  welfare.  life"  of the  The v a l i d i t y of this assumption i s suspect since water licence fees a r e u n i f o r m t h r o u g h o u t t h e p r o v i n c e - t h e y do n o t r e s p o n d t o t h e d i f f e r i n g a l t e r n a t i v e use v a l u e s o f 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 t h e a d d i t i o n a l e x p e n s e s r e q u i r e d t o 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 . I owe this a p p r o a c h 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 G a f f n e y {1974, 1 9 7 6 ) . 2  7  2  8  42  investment whose  will  lead  nominal  inflation. In  level  the  Investment  t o some d e g r e e , of  investment  funds  being  British  in  alternative  concept  one  rate  of  from  r e t u r n s to s o c i e t y  use o f t h e i n v e s t m e n t  again  represent,  investment  in  that, t h i s  i n t h e form  other  foregone  s e c t o r , i t would  These foregone  3 0  (mainly  is  by B.C. Hydro  have been i n t h e p r i v a t e  additional  have  of corporate  returns to society  funds  s h o u l d be i n c l u d e d  the opportunity cost o f c a p i t a l .  reflected  in  the cost of c a p i t a l  Funds b o r r o w e d i n Canada which  will  reduce  British  market w i l l dollar  other  Columbia. tend  (under  implications the  the  cost o f c a p i t a l  cost  spent  There a r e s e v e r a l other c o s t s  to  terms, or  with  Columbia. To t h e e x t e n t  t a x e s on income and c a p i t a l . from  year  opportunity  money b e i n g d i v e r t e d  would  generated  each  the appropriate r e a l  expense),  employed.  sectors  rises  in real  2 9  determining  interest  t o a c o n s t a n t charge  and/or h i g h e r  tend  investment Capital  initially a  actually to with  up  direct in  the value  exchange  which  are not  f a c e d by B.C. H y d r o .  push  borrowed  to r a i s e  flexible  society  interest or i n d i r e c t  of  t h e B.C. Hydro d e b t  a s s o c i a t e d with price  of  of  rate)  the with  for  costs  Canadian negative Also,  by t h e P r o v i n c e h a s a  i t i n terms of reduced  capital  rates  the i n t e r n a t i o n a l  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 .  guaranteeing  shadow p r i c e  will  to  other  availability  government-backed  This i s i n contrast to the existing straight line d e p r e c i a t i o n method w h i c h y i e l d s c o n s t a n t n o m i n a l ( f a l l i n g r e a l ) annual charges. This reduces the guantity of internallyg e n e r a t e d f u n d s and may l e a d t o " c a p i t a l e x h a u s t i o n " . I t might a l s o h a v e g e n e r a t e d a d d i t i o n a l r e t u r n s f r o m s c h o o l t a x e s s i n c e B.C. Hydro h a s a p a r t i a l e x e m p t i o n from t h e s e local taxes. 2  9  3  0  43  projects, the in  as  3 1  provincial an  interest In  taken and  this  to  be  will  stock.  premium o v e r  nominal coupon  society  real  applied  to  of  rate for  two  use  different  two  Hydro  and  others  social  discount  Once t h i s interested  where  rate. basic  of  represents present  from  rates the  by  real  on  capital  preference,  virtually  costs.  3 2  The  alternative  and  d i f f e r s from  the  riskreal  unwillingness while the  investment  be  capital  real  society's  r a t e s are  will  cost of  time  future  a tax  to  reflected  of c a p i t a l  social  the  open  rate.  consumption,  reflects  are separated  be  (undepreciated)  aggregate  received  e l s e w h e r e . The of the  cost  after-tax returns  capital  have  net  rate  discount  future cost  the  real  time p r e f e r e n c e  would  opportunity  real  the  bonds, used t o  opportunity  the  options  price could  average Canadian before-tax  by  exchange  policy  shadow  the be  fewer f i n a n c i a l  government. T h i s  I t exceeds the  social to  as  paper, the  approximated free  well  of  risk  real  returns  the  funds  wedge.  The  p r a c t i c e of  B.C.  combined  into a single  3 3  framework has  i n determining  the  been e s t a b l i s h e d , we  relevant  marginal c o s t s  shall  be  associated  This p r o b l e m has become p a r t i c u l a r l y a c u t e 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 o r d e r e d O n t a r i o Hydro t o cut back over $5 billion in i t s proposed c a p i t a l budget to 1985 because of concern over the strain the associated borrowing would have imposed on Ontario's credit. There are some i n d i c a t i o n s o f c o n c e r n i n V i c t o r i a a b o u t t h e s i z e o f B.C. Hydro *s future borrowing plans. T h i s may be w e l l b a s e d i n view o f reports of future large capital reguirements by the provincially-owned B.C. R a i l w a y Company. The i d e a o f u s i n g s e p a r a t e r a t e s o f social time preference and of cost of capital follows C a m p b e l l (1975) and Marglin 41963). F o r a d i s c u s s i o n o f t h e a s s u m p t i o n s i m p l i c i t i n s u c h an approach, see E e i s b e c k (1976). The s t a n d a r d r e a l d i s c o u n t r a t e used by B.C. Hydro is 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 p e r c e n t and the r e a l r a t e of s o c i a l t i m e preference w i l l be 5.0 percent. 3 1  3 2  3 3  44  with  demand s h o c k s o f v a r i o u s s i z e s ,  particular from  interest  the present  will  B.C.  society w i l l  customer  of  adjustment  to h i sc a p i t a l  Hydro  egual  stock.  to  price  resources  be most e f f i c i e n t l y  t h e n be made t o t h i s of shorter  This analysis w i l l B.C.  Hydro's  transmission analysis  o f t h e lower  is  as  not  published  is  programme  distinguishes shall  focus  customers be  made o f  smaller  as  net  marginal  used  concentrate electric  i n the long cost  a  will  run.  faces  a  society's  Adjustments  and p r i c e i n l i g h t  on t h e b u l k  power  side  of  s y s t e m - t h e g e n e r a t i o n and  level  transmission  and d i s t r i b u t i o n  system  the bulk s e c t o r , and very  little  as  for  is  available  thirds  of  to  additional  the  system  that  investment  the sector  that  systems. Consequently,  levels,  although  costs  involved  customers i n the system.  and  independent  Hydro's t o t a l  as w e l l as b e i n g  other e l e c t r i c  voltage  understanding  however, i t i s t h e b u l k  5 years,  i t from  the  cf  own  f o r two-  high  result  electricity-saving  cost  on 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 at  a  r u n demand v a r i a t i o n s .  As we have s e e n ,  i n the next  period. I t i s this  Only i f t h i s c u s t o m e r  this  extending  Authority's  thorough  responsible  size  Of  The  information  researcher.  a  basic marginal  integrated sectors.  face  making  marginal  of t h e impact  and d u r a t i o n .  be s h o c k s o f a c o n s t a n t  t o t h e end o f t h e s i m u l a t i o n  decrease i n c o s t s which  can  direction  with  serving  estimates in  we  large  will  also  supplying  the  45  3*4  Summary  In theory it  this  chapter,  outlined  the  basic  chapters to c a l c u l a t e Hydro's e l e c t r i c The  utilities. approach  at least  amongst  and i m p l e m e n t i n g  Hydro  not  claim  to  such  be,  meaningful  developed  definition  of  explicit  particularly  section  be  we  as  have  used i n t h e n e x t costs  for  in  pricing  marginal  results this cost  a s an e f f i c i e n t now  well  B.C.  currently  are  established  somewhat l e s s  i n u s e by  n o t , based  i n some  electric  B.C.  upon s u c h a  methodology b e i n g  American  way o f  The m e t h o d o l o g y f o r  a t h e o r y remains  and  reasonable approximations  methodology  pricing  procedures  The m a r g i n a l c o s t  generate  will  economists.  O n t a r i o Hydro and o t h e r N o r t h  provide  In the last  scarce resources i s  The r a t e s e t t i n g  principle.  pricing,  the a p p r o p r i a t e marginal  developed. do  the development o f t h e  system.  society's  accepted,  determining  not  traced  that  theory of marginal cost  allocating  by  have  and m e t h o d o l o g y o f m a r g i n a l c o s t  applies to electric  and  we  developed  utilities  instances,  but  may will  i n t h e c a s e o f B.C. H y d r o . The paper  relies  upon  i n t h e dynamic s e n s e ,  economic c o s t s i n i t s a n a l y s i s .  the  basic  and e m p l o y s  46  l i  THE  STRUCTURE OF  THE  MODEL  4. 1 I n t r o d u c t i o n In  this  designed  to estimate  electric and  s y s t e m . We  describe the  marginal  these  The  Hydro's i n t e g r a t e d  basic  electrical  function  demand  and  marginal  and  operation of  The  the  from  level  and  of  the  appropriate,  assumptions,  calculations  present  financial  B.C.  data  for  derived  largely  1975  for  that  Report  and,  from  t o 2059 and  has  is  to  given  the  a  take future  accounting  optimal  design  model o p e r a t e s  the  projects sufficient  the i n i t i a l  year.  (B.C.  ability  t o meet a  Future  of the and  w i t h i n B.C.  model b e g i n s  of  the  in  on  an  to bring  on  quadrupling  demand  and  contained  by  taking  Authority more  simulation period  B.C.  Hydro, 1975b). F i n a n c i a l  updating  numerous o f f i c i a l s  year  reported  from i n f o r m a t i o n  from a r e c e n t P r o s p e c t u s Clarification,  model  Hydro s y s t e m . The  actual figures  Heport  The  where  of demand.  values  b a s e d on  Force  theory,  economic c o s t s r e s u l t i n g  basis  1975  providing,  p r o j e c t i o n , determine the average  additional generation of the  the  overview  involved.  exogenous e n g i n e e r i n g  annual  parts,  b a c k g r o u n d on  modelling  p r o v i d i n g an  model  detail  of  by  c o s t s f o r B.C.  simulation  i t s component p a r t s . S u b s e q u e n t s e c t i o n s c o n t a i n more each  begin  computer  model  important  are  we  of the  about  and  chapter,  Annual  cost estimates in  the  data  (B.C.  detail  Hydro's  1975  are  Hydro,  were  are Task  primarily 1976b).  provided  by  Hydro. information  contained  in  two  •47  policy  subroutines  electrical existing then  energy  -  PGLD1  and  introduce By  to  calculate  longest  capacity)  and  e a c h major g e n e r a t i o n  peak  and  demand  (sub-transmission, increased  and  costs  transmission  f o r each type  resulting  incorporated  expected  or  energy  energy  next  l e a s t expensive required. the  engineering  of  distribution,  peak  also  has  facilities  contains  facility  SUPPLY,  the  and, using  is  of potential  able  to  This  projects i s  subroutine  demand w i t h  compares  future  expected  in  either  c a p a c i t y component i s f o r e c a s t , i t a p p r o v e s t h e p r o j e c t i n time f o r production  Subroutine new  SUPPLY  system,  takes  fully  t h e system  i n a cost  to  decisions  on  the  accountinq  minimizing  system a r e f e d i n t o s u b r o u t i n e  expansion  commence  t h i s i n f o r m a t i o n and for  fashion  and  various  of project. I t  t h e c u r r e n t demand f a c i n g B.C. H y d r o i n e a c h t i m e These  data f o r  e t c . ) t o meet  MCOST  and e c o n o m i c v a r i a b l e s f o r e a c h t y p e  operates  and  projects.  ranking  APPROVE., and  It  and peak c a p a c i t y . When a s h o r t f a l l  the  constructs  least-cost  profile)  f o r downstream  of generation  i n the  capability  project.  major p r o j e c t from  i n subroutine  energy c a p a b i l i t y  also  reguired  an e c o n o m i c a n a l y s i s o f t h e s e  The  (energy  demands. / S u b r o u t i n e  i n f o r m a t i o n on e a c h  when  and t o  subroutine  (investment  transformation,  electrical  operating  future  DEMAND i s  reguirements  most d e t a i l e d  economic  i n f o r m a t i o n on t h e i n v e s t m e n t  perform  i n f o r m a t i o n on  p r o j e c t s . Subroutine  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  the  former s u p p l i e s  any c h a n g e s i n f u t u r e demand f o r e c a s t s . f a r the  peaking  The  demand f o r e c a s t s and t h e l a t t e r  and committed g e n e r a t i o n  called  P0LS1,  in  period.  operation  COSTS which c a l c u l a t e s  light  of the  both  the  48  associated careful  tracking  interest etc.,  accounting  and e c o n o m i c c o s t s .  of o p e r a t i n g  costs,  payments, d e p r e c i a t i o n  of  appropriate outlined  a  KWH.  The  charges,  marginal cost  i n the l a s t  economic per  chapter.  average p r i c e s f o r t h e v a r i o u s the  local  net income o b j e c t i v e With  that  model, we t u r n  brief now t o  KWH  reguirements,  accounting)  analysis using  Finally,  i s done by  and p r o v i n c i a l t a x e s ,  financial  and y i e l d s t h e ( a v e r a g e h i s t o r i c a l  service"  The f o r m e r  "cost  determines  the  basic  subroutine  customer c l a s s e s  the  approach  BITES  to  of  adjusts  ensure  that  i s met. overview  examine  of in  the basic more  operation  detail  the  o f the  component  parts.  4.2 POLD1 And POLS 1 Subroutine forecasts Force  P0LD1  contains  f o r the period  Report.  This  introduce  deviations.  stabilize  at  net  electrical  1975-1990 as p r o v i d e d  provides In  a  demand  f o r the duration  demand  i n t h e 1975  base c a s e from  a l l cases,  t h e 1990 l e v e l  energy  which we is  Task later  assumed  to  of the s i m u l a t i o n  period. The system and,  demand i s split  in  forecast  f o r B.C.  between r e s i d e n t i a l ,  addition,  includes  reguirements of a p r i v a t e electricity  Hydro's  customers  is  the  utility. * 3  also  read  integrated  general  and b u l k  electric customers  anticipated  incremental  The  number  expected  i n . The n e t e n e r g y  of  demand  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 supplying r e s i d e n t s i n the south-central part o f B r i t i s h C o l u m b i a , 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 e x c e e d i t s own g e n e r a t i n g c a p a b i l i t y . 3 4  49  forecast for  s i x y e a r s hence f o r each customer c l a s s i s then  each  year  consistent the  15  with  year  projects  and  demand e x p e c t e d  is  be  used  later  the  provides B.C.  new  up  to  b a s i c i n f o r m a t i o n on  the  t o be  25  adjustment accept recent  above t h e  analyses  are  dates  for  read i n . Adjustments i n the  real  accuracy  e x p e r i e n c e s by  construction America.35 detailed  equivalent  u s i n g 0 and  i s i n c l u d e d because  the  of These  are  of  initial  B.C.  large  others  estimate  problems d u r i n q c o n s t r u c t i o n .  3 6  to  in light  of  with  the  projects result being  The  This  author  involved  could  standards  although  are performed.  engineered  revisions  The  p r o j e c t s i s assumed  1976  percent  here.  planning estimates  H y d r o and  custom-  upward  50  made  of a r e l u c t a n c e by t h e  cost estimation, higher  unforeseen  times o f  Approval  cost of a l l future generation  percent  sensitivity  lead  system.  c o s t s o f v a r i o u s components o f t h e s y s t e m capital  to determine  in  when  with  some  Hydro  a l r e a d y committed  real  f o r each y e a r  approved.  P0LS1  of  in  1975-1984. T h i s i n f o r m a t i o n i s  transmission projects,  Subroutine side  period  the net energy  years, should  supply  the  period  g e n e r a t i o n and six  in  fed  in  North  from  more  required  specific  or  number  W i t n e s s , f o r example, t h e r e c e n t K o o t e n a y Canal project by B.C. Hydro and t h e T r a n s - A l a s k a o i l p i p e l i n e , S y n c r u d e 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 a c c o u n t a n t s i n that they both prefer a s o l i d , e m p i r i c a l l y b a s e d 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 t h r e e c a s e s a r e t o be f o u n d i n c u r r e n t B.C. Hydro s i t u a t i o n s . E s t i m a t e s f o r Hat C r e e k c o a l generation keep rising as more detailed design work i s p e r f o r m e d (the 1976$ e s t i m a t e i s 64 p e r c e n t higher than the 1974$ figure ; new requirements by t h e p r o v i n c i a l C o m p t r o l l e r o f water r i g h t s w i l l r a i s e t h e c o s t s of t h e proposed Bevelstoke dam project; and s t r u c t u r a l w e a k n e s s e s i n t h e S i t e One dam on t h e P e a c e B i v e r now under construction will call 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 . 3 S  50  chosen  i s arbitrary  available test  the necessary  B.C.  operating  were a l s o a d j u s t e d increases are  regression  accurately  c o e f f i c i e n t s for various  facilities  Several  Analysis  annual r e a l  (1976c).  3  subroutine  so  the  that  they  1975  Task  can  be  figures (based on  Bevelstoke  approval fairly  t h e approval  Force  Report.  Project  occasion.  date f o r a l l  compared  using  dates f o r  projects  The  of  use  this  and i m p a c t o f t h e  dates.  DEMAND  DEMAND  takes  the  separate  f o r e c a s t s f r o m P0LD1, sums them t o o b t a i n transmission  obtained that  by Hydro  e n a b l e s us t o c h e c k on t h e a c c u r a c y  Subroutine  adds  used  construction  endogenously c a l c u l a t e d approval  4.3  those  These  fuel  7  MCOST. POLS3 c o n t a i n s  in  and f o s s i l  respectively.  with  a standardized  projects  subroutine  labour  v a r i a t i o n s o f POLS1 e x i s t and a r e used on  POLS2 p r o v i d e s  given  phenomenon.  to r e f l e c t  consistent  information  a n a l y s i s a n d judgment) i n t h e i r  Benefit-Cost  major  cost  was u n w i l l i n g t o make to  o f 2.25 and 2.0 p e r c e n t  generally  Hydro  historical  the s i g n i f i c a n c e of t h i s Annual  as  since  losses  from r e g r e s s i o n  must  be  supplied  total  (calculated  analysis)  net energy  by t h e g e n e r a t i n g  n e t demand,  using  t o achieve  demand  the  a  and  coefficient gross  demand  s t a t i o n s . The a n n u a l  T h i s s t u d y by B.C. Hydro a c t u a l l y has a b a s e c a s e a s s u m p t i o n of a r e a l o i l p r i c e i n c r e a s e o f 4.0 percent per year. Many analysts now assume t h a t w o r l d o i l p r i c e s w i l l r e m a i n c o n s t a n t i n r e a l t e r m s . T h i s p a p e r u s e s a r a t e o f 2.0 p e r c e n t b u t b e g i n s with t h e gas p r i c e s e t a t t h e i n t e r n a t i o n a l b o r d e r which, i n 1976, was s e v e r a l d o l l a r s below t h e BTU e g u i v a l e n t world o i l price. 3 7  51  maximum one-hour load  factor  gross  demand. The  shock  peak  anticipated  equations  of  demand i s d e r i v e d by a p p l y i n g  a  year.  provided  so  B.C.  Hydro  a r e a l s o designed  given  specified  by  magnitude  A separate  that  the  secton  of  (63.5 p e r c e n t )  so that  an  energy  c a n be i n t r o d u c e d  system  peak  load  factor  demand  the  system to the  demand  beginning  for this  may be a l t e r e d  shock  i na i s  t o varying  degrees. A final financial  information  DEMAND  f o r use l a t e r  B.C. H y d r o ' s a s s u m p t i o n s a b o u t its  own  interest  HJi  prior  deficiencies  of  i n t h e model. They i n c l u d e  as w e l l as data and m a t u r i t y  and  on i n t e r e s t  dates  for  debt  SUPPLY  generating  SUPPLY  DEMAND which p e r m i t s  of  marginal  subroutine.  represents  c o s t s . There The f i r s t  us l a t e r are  four  approval  dates  resulting  aggregate  calculated  i n SUPPLY.  HCOST  (generation an  i s bypassed  model,  i n response  an economic a n a l y s i s  primary  t o perform  this  functions  of  this  r e g u i r e d on each o f p r o j e c t s and t h e i r economic  us t o rank t h e p r o j e c t s i n APPROVE.  a n a l y s i s h a s been done, project  lines)  of  information  i s t o p r o v i d e t h e data  transmission  HCOST e n a b l i n g  heart  t o perform  p o s s i b l e upstream f a c i l i t i e s  associated  the  t h e f i n a n c i a l and e n g i n e e r i n g  to  in  pieces  t o 1976.  Subroutine  the  various  the future r a t e of i n f l a t i o n  coverage p o l i c y ,  payments, s i n k i n g f u n d issued  introduces  and  analysis Once  APPROVE  this sets  as d i c t a t e d by demand f o r e c a s t s , and t h e  engineering  and  financial  figures  are  52  In  order  approach, the over  35  production  different  triqqered, approval  either  in on  contained  by  each  These  working  1976  project.  d o l l a r s and  have been  switch  up  to  categories  Creek c o a l , East of the 1976  construction.  It  of  plant  are  Task F o r c e  two  stocks  factor  the cost  the  figures Beport, specific  estimates  into  changes t h a t  in  used  containing  service gas  the  later  sum as  of the a  additions  (hydro-electric,  turbine)  augmented. The  i s simply is  1975  real  on  an are  to bring  based  converts  by  expenditures  are  of  Once  3 8  w i t h MCOST o r  adjustment  new  this  may  3 9  period  and  an  for  modelled.  years in order  any  K o o t e n a y c o a l and  simulation dollars  six  modification  recognized.  are  construction  papers behind the  incorporates  required  investment p r o f i l e s  run  expenditures  Upon p r o j e c t c o m p l e t i o n , various  when  application of  This  and  projects  &PPBOVE,  of  updated through t h e to each  necessary d e t a i l  capabilities  a  in  stream. in  the  generation  date s e t  incurred project  to obtain  s i n c e the  first  base  for  Hat  start  i s measured  expenditures  to  in  during  determining  In the case of l a r g e p r o j e c t s with distinct and divisible generation Units, t h e s e U n i t s a r e t r e a t e d as s e p a r a t e p r o j e c t s whenever p o s s i b l e . T h i s a p p r o a c h assumes t h a t t h e 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 i n d e p e n d e n t o f when i t i s b u i l t within the 15 year framework we are considering. T h i s a s s u m p t i o n d o e s not a p p e a r u n r e a s o n a b l e i n l i g h t o f two c o n f l i c t i n g f o r c e s a t work. The f i r s t i s an o b s e r v e d t e n d e n c y f o r c o n s t r u c t i o n c o s t s t o 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 real construction costs is offset by any technological i m p r o v e m e n t s which m i g h t be i n c o r p o r a t e d i n t h e d e s i g n o f f u t u r e projects. These are unlikely to be v e r y l a r g e i n t h e c a s e o f hydro-electric f a c i l i t i e s , but may be more significant for thermal projects. a r e c e n t s t u d y done f o r B.C. H y d r o , however, i n d i c a t e d t h a t improvements in the efficiency of coal-fired f a c i l i t i e s a r e e x p e c t e d t o be no more t h a n 10 t o 15 p e r c e n t , and t h e s e a r e s t i l l 10 t o 15 y e a r s i n t h e f u t u r e . 3 8  3 9  53  operating dollars  costs.  The  (obtained  expenditure  by  second  by  stock  multiplying  that  year's  to  help  accounting  procedures. and  generating  facility  of  for  nominal),  peaking  the  information  energy  category  and  each  It  of  each  energy  is  These  facilities  (both  (the  in  real  entire critical  end a s w e l l as t h e a v e r a g e  1975  then  aggregated  o f p l a n t u n d e r a v e r a g e and  after  of  completion.  capability  (the e n t i r e  will  category  project  facilities.  an  traditional  stock  for  of plant i n service  completed  dollar  includes  upon p r o j e c t  generation  capacity  and v a l u e  the  i n generation  and a t y e a r  y e a r ) , peaking  in  on  a l l generation  conditions  category)  1976  construction.  capacity  c a p a b i l i t y f o r each c a t e g o r y water  during  Increases  v a r i a b l e s i n c l u d e investment and  index)  are a l s o recorded  detailed  aggregated  year's  in historic  d e t e r m i n e d e p r e c i a t i o n c h a r g e s under  capability  This  measured  each  price  endogenously c a l c u l a t e d i n t e r e s t serve  is  during  c a p a c i t y f o r each  plant  (the stock  plant  both  o f each  1976  and  historic  dollars). A similar separable various through its  major  transmission  generation a switch  associated  approval and  procedure i s followed  date  transmission  aggregate economic s t o c k s  The calculate  second  information major  associated  facilities  and f l o w s  the  of  of  and  disaggregate  i n this  subroutine  and f l o w s  project  i s undertaken,  need be m a i n t a i n e d  the economic s t o c k s  with  i n MCOST o r t h r o u g h an  The same t r a c i n g  function  one dozen  These t o o a r e t r i g g e r e d e i t h e r  to cost the generation  s e t i n APPROVE.  no e n g i n e e r i n g  projects  facilities.  coefficient  f o r t h e more t h a n  resulting  case.  SDPPLY from  although  i s  to  expansion  54  of  downstream f a c i l i t i e s .  following  classifications:  associated  with  transmission  lines  initiating at  (below  be  projects,  continuous.  linear The  investment  analysis  I n most c a s e s ,  cost of  the  year lagged  coefficient  past c o n s t a n t appropriate  used  dollar  Investment  .between  that r e g u i r e d to serve  be a l i n e a r  existing a the  relatively year  investment  in  s t o c k s o f new historic  Investment  change  each plant  in  i s assumed  to  in  in  on  and/or  demand.  discussion  and  customers  (which  expected  been  split  i s taken  lagged change i n the  growth  a  the b a s i s of  has  to  number  i n t h e peak demands o f  annual  of f a c i l i t y service  t o be  peak  i n miscellaneous e l e c t r i c  change  type  the  present  m i n o r i t e m , i s assumed t o be lagged  (below  Unlike  facilities  year  t h a t prompted by  customers.  one  new  initiating  c o s t s are taken  i s determined  in distribution  f u n c t i o n of t h e one  c u s t o m e r s ) and  facilities  about  sub-  transformation  plant.  expenditures  officials  not  facilities  electric  the  lines  transformation  expansion  costs.*o  of  volts),  i n these  into  projects,  distribution  miscellaneous  f u n c t i o n o f t h e one  real  with  and  divided  generation  500,000  level,  are  transmission  at the t r a n s m i s s i o n l e v e l ,  volts)  upstream  major  particular  the sub-transmission  25,000  These f a c i l i t i e s  a linear energy  function of demand.  i s accumulated  measured  in  plant,  both  in  The  separate 1976  and  dollars.  Still  i n the system  design  area, a t h i r d  responsibility  of  •o The a n a l y s i s o f e x p e n d i t u r e s 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 c a n be d i f f i c u l t due t o p r o b l e m s i n o b t a i n i n g and a l l o c a t i n g t h e a p p r o p r i a t e l y d i s a g g r e g a t e d c o s t i n f o r m a t i o n . This p r o b l e m i s l a r g e l y a v o i d e d i n t h i s p a p e r by a n a l y z i n g o n l y the v e r y l a r g e s t c u s t o m e r s (who t a k e electricity at the subtransmission level) and the very smallest customers (who r e g u i r e , i n a d d i t i o n , a l l t h e downstream f a c i l i t i e s ) .  55  SUPPLY i s t o d e t e r m i n e capacity the  over  the desired  reserve  margin  peak demand. T h i s d e p e n d s l a r g e l y  g e n e r a t i n g system  with c o a l - f i r e d  units  ranking  reserve  of  margin  capacity  new is  projects  specified  fourth  major  task o f t h i s  the q u a n t i t y and s o u r c e  o f energy  achieved  by  increasing  operating costs u n t i l  utilizing  hydro-electric and  are  designed  qenerated  generating  petroleum-fired supplied  so t h a t  by  advance).  Gross  available  export  to  these w i l l  demand  peaking  energy  society  are  attained.  year.  This  i s  in  order  of  is  met.  Thus,  Any  remaining  although  the  energy  system  is  is  that  t o be known s i x  generated  years  in  i n DEMAND p l u s t h e  i s e c o n o m i c t o s e r v e . B.C. Hydro i s between  total  energy  whatever water c o n d i t i o n s a r e s p e c i f i e d ) and demand whenever t h e m a r g i n a l below  A coefficient  proportion  determine  n o t be r e q u i r e d {because t h e demand,  demand t h a t  {under  firm  received. what  the  meet demand, f o l l o w e d by  t o seek t o e x p o r t t h e d i f f e r e n c e  capability gross  demand  Units.  imports,  each  facilities  gross  t h e r u n s r e p o r t e d h e r e , i s assumed  assumed  of  the desired  subroutine i s to  generating plants f i r s t  then  deficits  in  function  Once  of v a r i o u s types of g e n e r a t i n g equipment.  The  coal  a  a greater  facilities.  has been d e t e r m i n e d , as  peaking  on t h e n a t u r e o f  requiring  m a r g i n t h a n t h e more d e p e n d a b l e h y d r o - e l e c t r i c the  of  of  the with the  marginal a base c a s e  export  operating  revenue  that  value of  market  sought  .5 is  costs  would  be  indicates actually  56  JK5  MCOST  Subroutine  HCOST t a k e s  economic a n a l y s i s o f both projects cost  of each  project's are  with  their  life,  then  to  project's time  of  Units.  average annual  a present Depicted  major  generation  Each  4 1  year  and t h e  during  a  costs  adjusted  upward  them t o an end o f y e a r  position  and a r e  i s compounded  forward  i n a stock  v a r i a b l e which  rate of s o c i a l  rate raised  stock  time  t o a power r e f l e c t i n g  value of r e a l  algebraically,  preference.  Upon  i s d i v i d e d by t h e r e a l  e l a p s e d s i n c e 1976. T h i s s e r v e s  yield  the  costs are  termination, this  preference  years  cost  SUPPLY and p e r f o r m s an  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  transform  by t h e r e a l  from  associated transmission f a c i l i t i e s  real These  accumulated  each year  the  project's separable  determined.  slightly  the data  the  social  t h e number  of  t o d i s c o u n t c o s t s back t o  c o s t s a s viewed f r o m 1976. each  year  following  project i ' s  approval,  KCi,t = KCi,t-1  *  (1 + STP) + C i , t * <1 + S T P ) * * . 5  .,...(1)  Upon t e r m i n a t i o n o f 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 project  costs associated  i i n year t ;  The H e v e l s t o k e p r o j e c t , f o r example, has s i x g e n e r a t i o n w h i c h c a n be d e v e l o p e d a t d i f f e r e n t times. 4 1  with  Units  57  STP  i s the r e a l r a t e of s o c i a l time preference case value of  Ci,t  (with a base  .05);  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 ;  KCPVi i s the discounted  present  value of a l l r e a l c o s t s over  project i ' s l i f e ; n i s the number o f years elapsed s i n c e In  order  to  be  able  to  1976.  compare and  rank the  p r o j e c t s , these c o s t s must be d i v i d e d by a measure of output. water  We  use the incremental  conditions)  for those annual  energy c a p a b i l i t y  f o r the major p r o j e c t s , and  which are not designed  compounding  and  electrical  (under  average  peaking c a p a c i t y  t o generate energy.  f i n a l discounting  different  A  similar  procedure t o t h a t s e t  out above i s f o l l o w e d . As both the c o s t s and project  depend  separable  the  we  sources,* use  2  the  is  used  complete  r a t e of development of the p r o j e c t ' s  a base case must  be  the  1975  Task Force  to s e t a standard  system's  specified.  r a t e of development and  p r o j e c t s recommended i n the POLS2  a s s o c i a t e d with each  U n i t s and t h e i r i n t e r a c t i o n with  generation paper,  upon  output  In  other this  interdependence o f Report.  i n i t i a l approval  Subroutine date of  1975  f o r each major p r o j e c t . There associated the 1975  are  three  components  with  generation  and  to  the  operating  costs  transmission projects. Following  Task Force Report, f i x e d r e a l  annual  operating  costs  * T h i s i s p a r t i c u l a r l y t r u e f o r h y d r o - e l e c t r i c p r o j e c t s . For example, the e f f e c t on net output of a r i v e r d i v e r s i o n depends on the generating facilities on both r i v e r s a f f e c t e d by the diversion. 2  58  are  taken to  capital  be  cost  a c a t e g o r y - s p e c i f i c percentage of of  each  approach i n t r o d u c e d incorporation increase  of  (updated  We  this  to  non-fuel  of  gas  thousand  cubic  b a s e d on  feet B.C. net  a  turbine  plants  and  than  25  (Mcf)  (18.3  Hydro  was  p r i c e of  i s assumed  t o be at  $1.83  mills  per  KWH  due per  mills  the  per  c o a l , and  B.C.  to  the  per  This  is  transportation  at  the  t o an  Canada-  o i l price  cost  of  a t a l l gas  KWH.  ton,  less  This  than  figure  Authority's  well  1976.  Hydro of e x t r a c t i n g 4 4  of  approximately  in  average f u e l  $6.00 per  than  to be  ),  Mcf  i s equivalent  to  the  selection  taken  provincial royality.  of  Force i n our  is  the  value  Report f o r  plant  28  the  figures  price  revised cost  greater  the  in  opportunity  $1.80  this  described  The  the  percent  opportunity  fuel.  19 75  real  .  the Task  estimated  creek c o a l i s valued  paying  KWH  upward a d j u s t m e n t ,  The  a l s o use  i n the  to  results  a c t u a l l y paying  V a n c o u v e r , and  barrel.  more t h a n  coal  Burrard  export  border near  $11.00  third  the  of the  4 3  however, f r o m  per  modification  which  o v e r t i m e . We  in mills  total  previously  increases  v a r i a b l e c o s t s of  a small  ,  Hat  wage  only the  d o l l a r s ) suggested  at  what  The  paper i s  coefficient  depart,  natural  U.S.  real  1976  of some o f t h e  costs  in this  variable costs do  triple  project.  the  below  is  "most  the  onethe less  likely"  more  than  * The d i s t a n c e o f t h e B.C. Hydro gas t r a n s m i s s i o n l i n e f r o m t h e Westcoast pipeline (the wholesaler) to the B u r r a r d p l a n t i s g r e a t e r t h a n t h e d i s t a n c e f r o m t h e B.C. Hydro t a p t o t h e C a n a d a U.S. Border. This higher c o a l cost r e f l e c t s the opportunity cost concept employed i n t h i s p a p e r . However, i t s use may n o t be unrealistic i n l i g h t o f t h e p o s s i b i l i t y t h a t t h e P r o v i n c e may r a i s e i t s c o a l royalty to capture this economic rent. Alternatively, this a d j u s t m e n t c o u l d be v i e w e d as i n c o r p o r a t i n g some o f t h e 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. 3  4 4  59  $10.00  price  Commission  that  has  (B.C.E.C.,  been  suggested  1975). The  higher  open p i t c o a l , about  which r e l a t i v e l y  at  some o n e - t h i r d  $12.00  per  ton,  (including royalties Force  of  the  of  are  at  mentioned  two  percent  of  Three  with  employs  the  derived  by  used  cost by  Kootenay  of  valued  extraction  the  service  the  1975  Task  use  applied  to  latter of  a  the  that  reach  the  of  a  1976  1976$  oil  declining  used i n  projects.  40  years.  stock.*  straight  p r o j e c t and  Canadian  the  petroleum  The  straight line  dollar  actual  fuels price  a  line  5.7  used i n t h e  economy  and  case  figure of  an is  different Canada  by  comparison,  we  d e p r e c i a t i o n on  the  For  in  percent  Bank o f is  base  This  stock 6  performing  method u s i n g  b a l a n c e measure o f n e t  approach i s t h a t the  opportunity  expected economic l i f e  traditional of  at  the  p r i c e of o i l , n a t u r a l  of n o n - r e s i d e n t i a l c a p i t a l  also  life  result to  left  real  various  life  mid-1976 n e t c o n s t a n t  expected  are  the  life"  their  the  represent  d e p r e c i a t i o n charges are  weighting  classifications  model  East  1990.  "opportunity  average expected  the  annually  $14.50 i n  types of  and  earlier,  economic a n a l y s i s of the  This  Energy  i s known, i s  above t h e  assumed t o  the r i v e r  c o a l i s assumed  equivalent  the  use  As  5  and  rise  little  B.C.  Report.  rates.* gas  the  guality  at e x i s t i n g rates)  Water l i c e n c e f e e s cost  by  simply  annual  charge  capital  stock.  Canada's a  RDX2  different  * T h i s a s s u m p t i o n 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 prospective dam sites. 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 opportunity cost of the affected rivers i s generally relatively small. * This figure was calculated 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 C a n a d a ' s F i x e d C a p i t a l F l o w s and S t o c k s , 1972-76. 5  6  60  application  of t h e "opportunity  depreciation capital  charge  stock  i s  plus  life"  applied  new  to  investment  concept. In a l l cases, the the  previous  measured  year*s  in  real  net  terms.  Algebraically,  Dt = D * (Kt-1  • It)  ........^..........................(3)  where: Kt = (Kt-1  + It)  Dt i s t h e r e a l  * (1 - D) ;  depreciation  Kt  i s the net r e a l c a p i t a l  It  i sthe real  investment  D i s the relevant Following capital real  supply  in  the  tax  return  10.5  year.*  real  percent,  i s applied  capital  rate o f social  o f 3.0 p e r c e n t .  half that  generally  a 8  reasonable  Sensitivity  given  time preference  The  used annual  total  of c a p i t a l  of each  i s t a k e n t o be  used by B.C. H y d r o . T h i s that  the real  proxy, has averaged  a n a l y s i s i s performed  * This approach i s similar (1976) . *« See C a m p b e l l ( 1 9 7 5 ) . 7  as  i s t h e RDX2 a v e r a g e r e a l  t o t h e average net stock  of  i s the a f t e r - t a x  t o b u s i n e s s o f 7.5 p e r c e n t  model. T h e s e c o n d  be somewhat h i g h ,  bonds, past.*  concept, t h e annual c o s t  7  The  still  cost  rate.  o f two components. The f i r s t  on i n d u s t r i a l  percent  i n year t ;  i n year t ;  depreciation  price of capital  RDX2  stock  the opportunity  consists  charge i n year t ;  to that  return  f i g u r e may  on government  3 to 4 percent using  used  5.0  real  i n the  rates  i n Helliwell  of  et a l  61  2.5  and To  real  7.5  percent.  summarize  annual  costs  algebraically  Ci,t  =  this  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  associated  with  each  project,  we  present  t h e components o f t h e C i , t shown i n e q u a t i o n  &i,t * KGi,t  • E *  (Ki,t-1  + Bi,t * Qi,t + Di,t *  (Ki,t-1  the  (1).  + Ii,t)  «• K i , t ) / 2  ..{4)  where: Ci,t  are the r e a l associated  Ai,t  project  KGi,t i s the year Bi,t  with  i s the f i x e d for  t  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 p r o j e c t i i n year  real  annual  i i n year  i s the v a r i a b l e  capital  Di,t  year  ( f u e l and  i s the c o e f f i c i e n t  i s the net r e a l in  Ii,t  year  non-fuel)  annual  for project ( i n KHH)  stock); real  i i n year  of p r o j e c t  t;  i  t; reflectinq  method b e i n g employed Ki,t  c o s t of p r o j e c t i i n  i * s qross r e a l c a p i t a l  i s the e l e c t r i c a l output in  coefficient  t;  operatinq cost c o e f f i c i e n t Qi,t  t as per e q u a t i o n (1);  operatinq cost  accumulated r e a l (project  costs  the t y p e o f d e p r e c i a t i o n  on p r o j e c t  capital  i i n year  t;  stock associated with  project  t;  i s the r e a l  investment  E i s the c o e f f i c i e n t price of capital  i n project  reflecting  i i n year t ;  the b e f o r e - t a x r e a l  (assumed t o be  .105).  supply  i  62  JH-6 AREEQ.11 This  subroutine  operates i n a time horizon  of t h e p e r i o d  being  simulated  transmission  projects  and a p p r o v e s  when  future  peaking  capacity  and/or  peak  shocks,  i s calculated i n subroutine  obtained  projects. next  demand.  in  determined  i sexpected  the  basis  can  fill  the  s i x years  technical  criteria  t h o s e now i n u s e by Projects  are  environmental met.  approved  DEMAND  energy of  the  of  energy  using  and  future  any demand  the information  peaking  hence  are  used  to  B.C.  Hydro  and s u p p l y  appropriately  determine  only  as  future  explained  i f the  capacity  i s  generation  of  )  c a p a b i l i t y and augmented.  The  deficiences are in  Chapter  2. and  have  been  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  mentioned i n t h a t  consideration  on V a n c o u v e r I s l a n d  basis  MCOST  legal  i n t i m e f o r them t o come on  subroutine  from  technical,  i s  given  t o supply  does not f u l l y  economic c r i t e r i a  chapter  stream to  local  o f l i m i t a t i o n s on u n d e r w a t e r t r a n s m i s s i o n The  and/or  e x i s t i n g and a p p r o v e d  gap i s a p p r o v e d ,  restrictions  Special  turbines  short  and  capability  (based on r e s u l t s o b t a i n e d  approved  Those p r o j e c t s  year.  fall  generation  g r o s s demand, i n c l u d i n g  P0LD1.. F u t u r e  on  energy  ahead  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 , t h e  capacity  are  Future  least-cost project  that  to  new  s i x years  optimize  in  the  the  need  sixth  f o r gas  peak demand b e c a u s e  capacity. approval  dates  because o f the complexity  on that  Mould  be  conditions  involved.* are  considerations of  increasing  low  cost  as  cost  4.7  for their  to the  ranking  and  and  approval  incorporate  economic  P r o j e c t s are  ranked i n  order  complete development. R e l a t i v e l y given  priority  inexpensive  sources.  economically  guickly  optimal that  once  they  "middle U n i t s "  so  as  In s h o r t ,  5 0  technical criteria  to an  of  are major  displace existing attempt  timing  of  must be  met.  i s made t o  new  projects  s l  COSTS This subroutine  to  possible.  b r o u g h t on  thermal  the  recognize  p r o j e c t s are  are  approximate the subject  to  f e a s i b l e . , The  hydro p r o j e c t s cost  as  much as  diversion  technically  high  s e t so  However,  9  determine  p e r f o r m s two  annual  p r o c e d u r e s . These c o s t s nominal  dollars  and  costs are are  major f u n c t i o n s .  according  to  traditional  c a l c u l a t e d each then converted  The  year into  in  1976  first  is  accounting terms  of  dollars  and  * In o r d e r t o d e t e r m i n e the o p t i m a l economic t i m i n g o f a new, relatively large project which would d i s p l a c e a c u r r e n t h i g h c o s t m a r g i n a l s o u r c e , one would r e q u i r e information about the expected future qrowth r a t e i n demand, t h e r a t e o f d e v e l o p m e n t o f t h e d i f f e r e n t U n i t s o f the new p r o j e c t and the variance of several key parameters. Reliance s o l e l y on the technical 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 t h e c o s t c u r v e s as m i n o r q u a n t i t y c h a n q e s can have major cost implications. These instabilities 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 t h e c o s t s and b e n e f i t s of proceedinq w i t h or d e f e r r i n q a new project. The i n i t i a l U n i t s of a larqe hydro-electric project are expensive because of the h i q h c o s t s a s s o c i a t e d w i t h r e s e r v o i r and dam c o n s t r u c t i o n . The incremental costs of the "middle Units" are relatively low compared w i t h t h e a d d i t i o n a l e n e r g y t h a t w i l l be p r o v i d e d . The f i n a l U n i t s , however, p r o d u c e little new e n e r g y and t h u s show h i g h e r c o s t s p e r u n i t of o u t p u t . I f r e q u i r e d , t h e a p p r o v a l d a t e s s u q q e s t e d by t h e model c o u l d be m a n u a l l y a d j u s t e d t o f i n d t h e p r e c i s e plan which minimized the present value of c o s t s s u b j e c t t o the s a t i s f a c t i o n o f a l l technical criteria. 9  s  0  5 1  64  divided  by  measured  by  Fixed and  gross energy  are  the  later  measured  costs are  increased  to  in  through  coefficients  to  licence  school  New  total  the  new  and  maturity)  and  financial  p o l i c y on  shortfalls be  The economic  second  function  analysis  of  p r o c e d u r e s as  of the  their  economic  were used  Water taxes  B.C. amount  and  coefficient  life  of  in  new  historic  difference  between  (includinq  sinking  fund  repayment  of  internally  o f t h e s e new  subroutine  The  principal under  Interest  is  at new  payments bonds  1976. to  perform  associated  analysis follows  i n comparing  the  outstanding  before  change i n c o s t s  earlier.  a  (as measured  bonds i s s u e d  this  5 2  land  1975 of  income l e v e l s .  basis  commitments on  demand s h o c k i n t r o d u c e d basic  the  are  the  in  net  (as  price-adjusted  and  product  make up  generated  desired  of  set at  in service  level  costs  in effect in  expected  requirements  what can  the  as  plant i n service  'grants'  the  issued to  t h e n d e t e r m i n e d on as  first  of the  1975  sources a c t u a l l y u s e d .  by  plant  bonds a r e  financial  well  KWH  price-adjusted  operating  p r o c e d u r e s now  inverse  the  contributions  as  the  o f new  municipal  augmented  dollars).  are  taxes,  subsequently  and  per  their  various  Variable  generating  charges are  projects  cost  s e t at  application  Depreciation  representing  real  applying  the  the  c a l c u l a t e d using  are  by  dollars).  determined  are  initially  different categories  1976  fees,  to get  accountant.  operating  coefficients  production  possible  an  with the  the same  projects  in  In o r d e r t o be c o n s i s t e n t w i t h c o s t s used in the economic analysis, and b e c a u s e 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 t h e c u r r e n t s i t u a t i o n , the opportunity (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 t h e a c c o u n t i n g section. S 2  65  MCOST. T h i s t i m e , however, we whole,  and  positive  to  opportunity  charges. by  wish  We  and  various  grouped  examine value -  into  operating  post-1975  operating  opportunity  appropriate,  to  By  the  average  measure o f  determined  percent  a p p l i e d to the  smallest  customers  then  in  this  brought in  the  run  and  of  gross  real  cost  new  costs  a  fixed  incurred  of  5.7  the  are  variable  each  the  asset  using  t a k e n on The  where  c o s t of  capital  p r i c e of  while  the  down  10.5  stock.  costs associated  categories  the  a declining  post-1975 c a p i t a l  determined  those  by  r e a l supply  real  each  applied,  calculated  stock.  to  while  produced  percent  before-tax  average net  are  are  homogeneous  applied  c a p i t a l stock  guantity  rate  facilities  are  coefficients  total  only  a r e compounded  back  time preference. instance stream  to  forward  end  of the  1976,  with  largest  to  annually, simulation  again  using  A simulation period of  to represent between  discounted one  any  the  a  c o s t s with  relatively  cost c o e f f i c i e n t s  q u a n t i t i e s , to the  on  and  as  the  sub-  level.  discounted  social  those  downstream  categories  customers  These c o s t s relevant  and  a l l asset categories  require  transmission  on  variable  post-1975 c a p i t a l  using  summing a c r o s s  the  impact  Annual d e p r e c i a t i o n c h a r g e s are  economy-wide  is  all  generating  category's  balance  the  system  l a r g e s t customers.  different  assets. Fixed  category.  i n t e r e s t e d i n the  a l s o w i s h t o d i s t i n g u i s h between  the s m a l l e s t The  are  1975  present  an  average l i f e  and  value  1990.  By  as period  the 55  with  years  f o r new  comparing  the  the  and  are  real rate  o f c o s t s between t h e  c o n t a i n i n g a demand s h o c k ,  are  is  of  used  facilities the  change  base  case  corresponding  66  change  in  output can The  the be  s u p p l i e d , a marginal c o s t per  followed  algebraically  F o r each  of  * KGj,t  <Kj,t-1  for  the  economic  analysis  are  below.  asset category  = Aj#t E *  unit  attained.  procedures  highlighted  Cj,t  quantity  j i n each  year  t,  + B j , t * Qj,t * D *  (Kj,t-1  * II,t) +  + Kj,t)/2  ..(5)  where: Cj,t  are the r e a l opportunity year  Aj,t  fixed  category  KGj,t i s category in Bj,t  year  real  annual  j i n year  coefficient  capital  stock  output  annual  f o r category {in KWH)  real  j i n year  produced  by  j i n year t ;  i s category year  non-fuel)  cost coefficient  D i s the d e p r e c i a t i o n charge  Ij,t  j in  t;  { f u e l and  i s the e l e c t r i c a l  in  operating cost  j * s post-1975 gross r e a l  i s the v a r i a b l e  category  Kj,t  asset category  t;  operating Qj,t  c o s t s a s s o c i a t e d with  capital  t;  i s the for  o p e r a t i n g , d e p r e c i a t i o n and  j»s  coefficient  of  .057;  post-1975 net r e a l c a p i t a l  stock  t;  i s the r e a l  investment  E i s the before-tax r e a l coefficient  of  .105.  i n category  supply  price  of  j i n year capital  t;  t;  For  customer c l a s s  k,  x Ck,t  =  Cj,t  1,...,55 ...  t =  ....{  where: x i s the  number o f a s s e t  customer c l a s s  Each y e a r  during  categories required  to  serve  k.  the  simulation  period,  K C k , t = KCk,t-1 *  (1 + STP)  + Ck,t  *  (1  • STP)**.5  ..-..(  KQk,t =  (1 + STP)  + Qk,t  *  (1 + S T P ) * * . 5  {  and  KQk,t-1 *  where: KCk,t i s t h e with STP  stock  customer c l a s s  i s the r e a l  KQk,t i s t h e  i s the  value  stock of  associated  k i n year  r a t e of s o c i a l  a base c a s e  Qk,t  of accumulated r e a l  with  gross  of  costs associated  t;  time p r e f e r e n c e  (with  .05);  accumulated  gross  production  s u p p l y i n g customer c l a s s  production  s u p p l y i n g customer c l a s s  ( i n KWH)  k i n year  associated  k i n year  t.  with  t  68  At  t h e end o f t h e s i m u l a t i o n  KCPVk = KCk, t /  period.  (1 + STP) **n  (9)  and  KQPVk = KQk,t / {1 + S T P ) * * n  (10)  where: KCPVk i s t h e d i s c o u n t e d opportunity  the simulation  KQPVk i s t h e d i s c o u n t e d  during n  present  associated  the simulation  i s t h e number o f y e a r s  marginal  (KCPVk,base  cost  with  supplying  customer  period;  value  of a l l gross  supplying  customer  class k  period;  period (53).  per u n i t o f output f o r customer c l a s s k  - KCPVk,shock)  (KQPVk,base -  with  of a l l real  between t h e end o f 1976 a n d t h e  end o f t h e s i m u l a t i o n  The  value  costs associated  c l a s s k during  production  present  /  KQPVk,shock)  (11)  where: the  s u b s c r i p t s b a s e and s h o c k i n d i c a t e t h e v a l u e v a r i a b l e s under respectively.  base c a s e and demand s h o c k  of these conditions,  69  kJL  RATES This  nominal using of  subroutine  p r o v i d e s an i n d i c a t i o n o f f u t u r e  average e l e c t r i c i t y  the information  COSTS.  utility  Revenues  average  differences  from  residential,  are c a l c u l a t e d  prices  and  that  by  an a d j u s t m e n t  reguired  t o meet t o t a l  i n average p r i c e s . This  i s held  constant  response t o t h e changed  be  new m a r g i n a l rate  i n r e a l terms)  structure.  will will  section  bulk,  private  existing  and  anticipated  be  generated  be  eliminated  adjustment f o r the  classes  i s t h e same  export  price  and assumes a z e r o demand  c h a p t e r o f t h i s p a p e r , t h e model  so as t o permit prices that  on  and  prices.  the a p p l i c a t i o n s  extended  (except  accounting  s a l e s . Any  nominal c o s t s  p e r c e n t a g e change f o r a l l c l a s s e s  For  based  forecast  customer  general,  between t h e n o m i n a l r e v e n u e t h a t  and  which  f o r various  from t h e c o n v e n t i o n a l  and e x p o r t s a l e s  committed  prices  real  will  appropriate be  will  demand r e s p o n s e s t o t h e  incorporated  in  the  revised  70  5jt THE In  this  simulation first  chapter  runs using  section  function;  se  the  reports  the  present  the  forecasts  m a r g i n a l economic c o s t s .  A l l three  from  those  in  interpretation  5.1  Project  5.1.1  analyses the of  Costing  results  And  costing using  and  a  The  ranking  conventional  presents various  estimates  sections  the  which key  case,  computer  as  provide  results  assumptions are well  as  of  altered  attempt  an  performed  in  obtained.  Ranking  Base C a s e The  results  of  s u b r o u t i n e MCOST a r e are  in  base  the  third  of  j u s t been o u t l i n e d .  costs  the  sensitivity  has  results  project  a c c o u n t i n g a p p r o a c h ; and  of  the  model t h a t on  second  RESULTS  grouped  the  project  presented  according  to  costing  i n Table  whether  1.  they  analysis  Generation are  heing  projects considered  primarily  for their contribution  to energy c a p a b i l i t y or  capacity.  They a r e  each c a t e g o r y  in-service These  dates  dates  results  a l l projects  are  social  and  the  the  1975  existing constraints  of gas  the  Hat  i n the  Task f o r c e  are  of  Report.  technical,  legal,  expected  C r e e k and  turbines  order  to  be  East  Kootenay  for  Vancouver  proposed  are.hydro-electric.  a s s u m p t i o n s used  that  in  when  exception  plants  T h r e e key  within  proposed  and/or  overcome. With t h e  Island,  as  indicate  environmental  coal-fired  ranked  peaking  in  real c a p i t a l costs  generating  the  exceed p r e s e n t  base  case  estimates  by  TABLE 1 COSTING OF GENERATION PROJECTS ENERGY PROJECTS  (1) UNIT NO.  (2) (3) EARLIEST AVERAGE POSSIBLE ENERGY IN-SERVICE CAPABILITY DATE (MM KWH)  (4) PEAKING CAPACITY (M W)  (5) BASE CASE  ( ) 6  CAPITAL COST  NO COST OVERRUN  SITE ONE  (?)  (8)  (9)  STP  (10) (11) DEPRECIATION' !  50% COST OVERRUN  CONVENTIONAL STRAIGHT LINE  2.5%  7.5% '  DECLINING "E"AL4*CE METHOD  16  11  16  15  13  -  1-4  1979  3150  700  13  11  1-6  1981  7970  2700  14  12  17  11  17  16  14  1-4  1982  13,680  2000  19  17  21  19  20  19  19  1  1984  875  2  2  3  2  3  2  2  1  1985  3828  7  HAT CREEK II  6  .8  6  8  S  7  5-8  1985  19,160  2800  18  EAST KOOTENAY  16  20  18  18  IS  18  1-2  1983  9580  1400  17  16  IS  17  17  17  17  900  19  16  22  15  22  21  19  (now under const.) REVEL-STOKE HAT CREEK I KOOTENAY DIVERSION MCGREGOR DIVERSION (assumes Site C)  •  SITE C (without McGregor Div.) CAPACITY PROJECTS VANCOUVER ISLAND GAS TURBINES G.M. SHEDM  1-4  1984 4290  1-2 10  1314  ($/KW) 300  206  201  212  214  199  206  204  275  10  MICA  8  12  8  12  11  10  5  400  7  MICA  6  8  6  8  8  7  6  400  7  6  8  6  8  7  7  EEVELSTOKE  5  450  11  REVELSTOKE  9  13  &  12  12  10  6  450  10  SEVEN MILE  8  12  S  11  11  10  4  175  15  12  18  12  17  16  14  75  72  25  percent,  percent  that  and  depreciation the  real  that  r a t e of s o c i a l time p r e f e r e n c e  the  i n the thermal  plant  opportunity  value)  i s 19  Site  plant should A  be  on  comprising  c o s t s per  turn  upwards  the  the  Hat  mills  per  KWH,  while  Units  3  production  at t h i s  analysis costs  Units  that  of  the  fall  fully  at  of its  i n cost  coal-fired  on  5 and used  assumptions separable  the  6 add  and  costs  the  of 16  costed  at  14  mills  costs  to peaking  to s u g g e s t  often  Thus f o r  show a c o s t o f  only  Units  then  incremental  was  expected,  developed.  developed  2 together  based  i s later  priced  p r o j e c t . As would be  each i s r e s p o n s i b l e f o r , are  information  and  3 and  8  capacity.  appropriate  rate  development of each p r o j e c t . We  per  t u r n now  unit  t h r e e key  5.1.2  t o examine the impact  economic  cost resulting  assumptions l i s t e d  Sensitivity Columns 6 and  the  with  initially  its  1 and  4,  put  cost  similarity  case  p r o j e c t i s more f u l l y  p r o j e c t with  and  base  associated  mills respectively. Units This  under  of output  the  life" To  operating  Creek  5.0  stage.  major g e n e r a t i o n unit  t o use.  gas  C h y d r o p r o j e c t and  as  Sevelstoke  mills  natural  The  noted  each  technigue  KWH.  the  these  {with  is  "opportunity  per  further  performed  line  t a b l e i n p e r s p e c t i v e , the  Burrard  between t h e  straight  method i s t h e a p p r o p r i a t e  numbers  the  the  board"  i n the  on  absolute  and  relative  from a change i n each o f last  the  paragraph.  Analysis 7 of Table  capital  1 r e v e a l the  results  c o s t a d j u s t m e n t s of z e r o  and  of fifty  "across percent  73  respectively.53 (which  are  project's  costs.  have a s t r o n g  C project The  impact  should  7.5  percent, future  over  higher  unit  STP r a t e .  these changes, with the  different  the  declining  a higher  present  of production.  STP  rate  of  the  value  through the  This  will  lead  impact  capital  in  The o p p o s i t e  of  He a g a i n s e e t h e d i f f e r e n t i a l  projects  depreciation  t o 2.5 and  discounting  of  project,  real  i n the  the  cclumns  the  applies  intensive  projects  more  dependent  o f the  on  this  assumption.  Table  procedures  hydro  v a r i a t i o n . The r a n k i n g  i s even  t h a n on t h e c a p i t a l c o s t final  varying  a greater  the  more s e n s i t i v e t o t h i s  C and Hat C r e e k  The  of  Because  costs.  this  a t Hat C r e e k .  implies  in  although  whether t h e S i t e  (STP) f r o m 5.0 p e r c e n t  i n the c o s t s  discounted  variations  p r o j e c t s . Indeed  ( w h i c h i s assumed t o be c o n s t a n t  than  of a reduced  these  each  variable  of a l l p r o j e c t s ,  before a plant  reduction  that  costs  to  unchanged  i n determining  time charged t o each  life)  variable  coefficient  leave  costs  i s critical  a h i g h e r STP r a t e  project's  Site  will  time preference  produced  being  a  with t h e c o a l - f i r e d  cause a greater  case  but  on t h e u n i t  proceed  quantity  to  applying  r e l a t i v e to the present.  costs  will  a f f e c t f i x e d operating  next columns i n d i c a t e t h e impact  of s o c i a l  real  will  I t i s not s u r p r i s i n g then  impact  rate  the  by  cost)  e f f e c t i s smaller  differential  of  changes  determined  capital  operating  the  The  1  show  discussed  the  e f f e c t o f the  i n the l a s t  chapter.  a b e t t e r a p p r o a c h would be t o c h o o s e possible capital cost variations on t h e b a s i s o f p r e s e n t knowledge and e x p e r i e n c e f o r e a c h p r o j e c t . Thus t h e c a p i t a l c o s t estimate of a relatively standard design hydro project on a w e l l s u r v e y e d s i t e would l i k e l y be more a c c u r a t e t h a n t h a t o f t h e f i r s t c o a l - ^ f i r e d plant e v e r t o be b u i l t by B.C. Hydro. 5 3  74  Standard  straight  expected  life  greater  than  facilities). under cost  the  is  life"  the  the  project's  Creek  is  method  i s higher  since  declining  as  In  the  dominate.  overwhelms t h i s  unit cost  f o r projects (such  Later,  operating  guickly  dependent  employed. The s i m i l a r i t y  the  to higher  f o r the  The percent gives  total  costs  almost  method in  will  with t h i s  balanced  by  costs  projects  to that  that  of the  rate of  stock  to those generated  by t h e  method. The  method i n t h e e a r l y  lower  costs we  i n later  will  higher  years  are  years.  This  later  COSTS b e c a u s e o f t h e d i f f i c u l t i e s  of t e r m i n a t i n g  5.7  measure o f c a p i t a l  depreciation  prove h e l p f u l , s i n c e  i n subroutine  keeping track  unit  straight line  associated  exactly  similarity  similar  life"  close  policy  the f a c t  annual d e p r e c i a t i o n  to a d e c l i n i n g balance  remarkably  "opportunity  life  over  life.  use o f t h e economy-wide applied  costs  thermal  expected  economy-wide a v e r a g e  of c a p i t a l  o f S i t e C and Hat  these  an  depreciation  type of depreciation  cost  stock  "opportunity  total  p r o c e d u r e s r e s u l t s from  have  lower  net  cost  under t h e two d e p r e c i a t i o n projects  a  lower  the higher  the  i n unit  life  as h y d r o - e l e c t r i c  to  Thus t h e r a n k i n g  on  with a  as under t h e  years  however,  life.  asset's  charges are  i t i s applied  early  the  f o r the l o n g - l i v e d a s s e t s , the  component and l e a d s  also  on  the annual d e p r e c i a t i o n  conventional  not  based  economy-wide a v e r a g e  although  approach.  charges  depreciation  y i e l d s a higher  of c a p i t a l  which  line  use  this  inherent  dates f o r a v a r i e t y of d i f f e r e n t  projects. A l t h o u g h n o t shown on T a b l e the  impact  of  1, a  sensitivity  d i f f e r e n t assumptions about  analysis  fuel costs  was  of also  75  performed. I f the extraction  costs  opportunity  cost  three  coal  cost of coal plus used  these thermal  today's  i n the  projects  i s taken  to  be  the  royalty rates  base  shown f a l l  case), by  (rather than  unit  costs  2 m i l l s per  p l a n t s a c l e a r f a v o u r i t e over  anticipated  KWH.  the  the  for This  Site  the makes  C  hydro  facility.  5.1.3  Project A  first  might  glance  suggest  suggested  Banking  a  by  the  this  the  base the  apparent  to  date.  Hat  before  difference  two  operation  case of the  important The with  reliability  very  to  costs,  East  first  the  coal  not  a d o p t e d by  Kootenay The  two  possible of  1  ranking B.C.  thermal diversion  scheduled  reflected  concerns i t s distance  important of  implications  transmission c o a l . B.C.  i n the  area  and,  by  B.C.  in-service  Hat  Creek  I  the  APPROVE i s t h e Task  Force  this the  from t h e  project economic  major  load and  for  the  stability  system.  The  second  centres  hold  mining  as  project  these reasons,  in  H y d r o does n o t  For  1975  earliest  the  Kootenay c o a l p l a n t ,  this  its  are  development  f a r i n i t s a n a l y s i s of  subroutine in  the  East  is illusory.  a t the  detractions  around a c c e s s to the rights  of t h e  that  i n Table  proceed.  the  analysis. centres,  low  listed  between  r e s u l t s and  exception  C r e e k I I must a w a i t  i t can  In has  begin  projects  variation  case  schemes, w i t h t h e i r u n u s u a l l y Hydro  energy  substantial  H y d r o . However, w i t h plant,  at  now  a r e s u l t has  not  proceeded  option. ordering  same as t h a t Beport.  that  i s adopted  recommended by  Site C  i s assumed  B.C.  in  Hydro  t o come  on  76  stream  after  capacity  is  East  reguired. * Diversion  of  the  McGregor D i v e r s i o n Site  C  hydro  possible, generating The  to  case  unit  f o r some e x p l a n a t i o n .  are  reguired  lower  because of  transmission  results  area.  from the capacity  costs The  The  high  factor  River,  while  options  1984  in time.  The  Revelstoke  and  forecast  as  need  not  a saving  tenth  turbines  power  unit  peaking  on  to  cost  soon  as  for  new  projects  also  Vancouver  Unit  factor  now  at  this  50  of  percent.  any  Shrum  of  plant  this  appear i n our we  can  with t h a t  5 5  1 a  figure substantially,  of  performing  projects,  capacity  electricity-  the on  a d d i t i o n a l energy, can  does not  i n a manner c o n s i s t e n t  the  the  Island  f i g u r e shown i n T a b l e  below t h a t  producing  which  capacity  would r e d u c e t h i s  more c o s t l y U n i t s  for  gas  assumed c a p a c i t y  p r o j e c t s . The  Thus  the  operational  f o r the  lines carrying  peaking  providing  of  a n t i c i p a t e d l i m i t a t i o n s on  a l t h o u g h i t would n e v e r f a l l  displace  a  inexpensive  facilities. . base  deficient  being  and  of the  be  generating  available  balance  slated to  there  small  to be  "middle Units"  are  call  of the  additional the  i s programmed  the  projects  i f  from  supply-demand and  subject  coal  Energy  5  Kootenay R i v e r regardless  Kootenay  again adopted  hydro  the be  role,  Peace  used  to  thereby  analysis. rank the by  B.C.  various Hydro  * This is consistent with the base case ranking i n our a n a l y s i s . However, as has been n o t e d , t h e o p t i m a l p o s i t i o n i n g o f Site C relative to the thermal projects is sensitive to a l t e r a t i o n s i n s e v e r a l key a s s u m p t i o n s . T h e r e 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 s t a t e m e n t s i n t h e 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 t h e e y e s o f B.C. Hydro. I t d i d n o t f i g u r e i n t h e 1975-1990 P l a n p r o p o s e d by the 1975 Task F o r c e Report. C a p a c i t y f a c t o r i s t h e r a t i o o f t h e a v e r a g e l o a d on a machine for the p e r i o d of time c o n s i d e r e d , t o the c a p a c i t y r a t i n g of the machine. 5  5 5  77  in  1975.  the  remaining  forecast  Conventional  turbines  b r o u g h t on  system reaches a s p e c i f i e d triggered  deficit,  are  i n the  as  order  required  when  level.  to  meet  i n which t h e y a r e  5 6  a  listed  Accounting  Projections  Base C a s e This  section  accounting B.C. the  1975  Task  following in  percent  electrical  key  The  key to  a v e r a g e and  next s e c t i o n we  as  are  between  nominal e f f e c t i v e the  1975-1990  assumptions  subroutine that  with  fuel will  variables  those  the  assumptions.  10 p e r c e n t  throughout  Other  financial  now  based  The  and  i n t e r e s t r a t e on period.  that  by  specified  cost  inflation  1976-1979  are t h a t the  APPROVE,  basic  upon  employed  demand growth r a t e i s t h a t  Force Report, exogenous  1975,  thereafter.  according  forecasts  conventions consistent  Hydro. The  percent  10  gas  1.  5.2.1  the  total  p r o j e c t s are  capacity  Table  5.2  in  Vancouver I s l a n d  demand f a c i n g t h e  The  in  The  data rate i s 5  new  and 15  percent bonds i s  5 7  projects water  are  initiated  conditions  i s p r i c e d at i t s opportunity  value.  r e l a x e a c h o f t h e s e a s s u m p t i o n s and  In  are the  examine  We assume t h a t t h e r e g i o n a l b a l a n c e o f e l e c t r i c a l demand w i l l h o l d t h e p a t t e r n s u g g e s t e d by B.C. Hydro in the Task Force Report. This implies t h a t t h e demand on t h e 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 t h e p r o v i n c i a l demand is a t t h e l e v e l w h i c h t r i g g e r e d t h e t u r b i n e s i n t h e 1975 Report. The f a i l u r e by B.C. Hydro to link inflation and nominal interest rates could p r o v e t o be a p r o b l e m . However, o v e r t h e 1975-1990 p e r i o d , t h e rate of inflation averages an annual compound r a t e of 6.4 p e r c e n t which i s not i n c o n s i s t e n t w i t h a 10 p e r c e n t n o m i n a l r a t e on low r i s k bonds. 5 6  5  7  78  the r e s u l t i n g Table  impact.,  2  assumptions.  summarizes 'Energy  some  Generated  of  t h e p r o j e c t i o n s under  c o n s i s t s o f g r o s s demand i n B.C.  1  H y d r o ' s s e r v i c e a r e a p l u s any e x p o r t s t h a t attractive province  is  into  nominal  Debt*  i s t h e sum  calculated  generated  each  fixed  taxes, depreciation also  year  p e r KWH* i s s i m p l y  assumptions, over  results  to  in  total  capital  level  index.  debt  excess  s s  'Gross  will  still  reguired of  what  t o meet can  a l l local  charges  'Annual  and  water  and any n e t i n c o m e .  terms.  annual c o s t s  be  The f i n a l  (now  column,  converted  to  generated.  Analysis appreciate  period  when  are reported i n Table  We f i r s t  in  nominal  the  we e x a m i n e t h e i m p a c t  this  real  t h e new n e t income p o l i c y .  by t h e e n e r g y  order  t h e new  and n e t i n t e r e s t  •Cost  In  the  the  assumption).  t o 1976 t h a t  and o p e r a t i n g c o s t s ,  expressed  Sensitivity  prior  plus  under  are  5.2.2  the price  reguirements  They  1976$) d i v i d e d  summing  through  internally  comprise  by  of bonds i s s u e d  c a p i t a l and f i n a n c i a l  KWH  outside  t o meed demand growth and c o n v e r t i n g t h e s e  dollars  outstanding  Costs*  those  (under t h e 50 p e r c e n t o f e x p o r t p o t e n t i a l  expenditures reguired  be  a r e both e c o n o m i c a l l y  t o t h e A u t h o r i t y and demanded by  'Investment'  these  disengage  importance  of  on t h e a v e r a g e  these assumptions  s e v e r a l key  real  cost  per  a r e a l t e r e d . The  3.  s u b r o u t i n e APPROVE and  explicitly  read  I t i s i n t e r e s t i n g t o n o t e t h a t t h e 1976-19 81 i n v e s t m e n t shown here totals within H p e r c e n t o f t h a t p r o j e c t e d i n a November 1976 P r o s p e c t u s by t h e A u t h o r i t y (1976b,18). In f a c t , their f i g u r e s a r e h i g h e r t h a n t h o s e shown i n t h i s T a b l e . 5  9  TABLE 2 1976-1990 PROJECTION  YEAR  ENERGY GENERATED (MM KWH/YR)  INVESTMENT (MM NOMINAL $/YR)  OF KEY FINANCIAL  GROSS DEBT HISTORIC $ )  VARIABLES  ANNUAL COSTS (MM NOMINAL $ )  COST PER KWH (1976 $) (MILLS/KWH)  1976  25,102  526  3932  463  , 18  1977  28,402  542  4340  535  17  1978  31,544  702  4960  624  16  1979  35,321  983  5883  800  17  1980  39,097  1181  6981  990  17  1981  43,095  1019  7834  1120  17  1982  47,427  1123  8721  1413  18  1983  52,092  1133  9629  1600  18  1984  56,868  1125  10,458  1925  19  1985  61,866  1344  11,463  2191  19  1986  67,198  1428  12,488  2457  19  1987  72,973  1603  13,674  2879  19  1988  78,860  1729  14,885  3226  19  1989  84,858  1790  16,208  3775  20  1990  91,189  1400  17,053  4144  19  •  •  80  in  t h e a p p r o p r i a t e a p p r o v a l d a t e s f o r major p r o j e c t s a s g i v e n i n  the  1975  Task  Force  Report.  1976-1990 p e r i o d  falls  reasons  r e d u c t i o n . The f i r s t  in  for this  the  Task  Force  from  Average c o s t  18.1 t o 17.9 m i l l s .  f o r new  the l o s s  desired  maximum i n t h r e e d i f f e r e n t  other  hand,  load  four  the Task  F o r c e . The s e c o n d  in  Task  the  projects.  several  Task F o r c e t h a n thereby  shows thus  of  are  the approval  rising  reliability  two dates  above i t s  projects  c r i t e r i o n and  a year e a r l i e r  than  the f i n e tuning  the  relatively  high  D n i t s are brought  required gas-fired  from  a  energy.,  cost  energy  builds this  margin  project.  of  on e a r l i e r  technical  does done  running i n the  perspective,  S u b r o u t i n e APPROVE  S i t e C f o r commencement i n 1990 w h i l e t h e  a very s l i m never  are  y e a r s . S u b r o u t i n e APPROVE, on  reason concerns  coal-fired  displacing  initiates  There  F o r c e w h i c h e n a b l e s o p t i m a l e c o n o m i c t i m i n g o f new  Because  Burrard,  from  the stated  of t h e s e peaking  during the  projects are too late to  probability  follows  approves  i s that  peaking  prevent  the  of  p e r KWH  Task  also Force  i n 1990 {the t e r m i n a l y e a r ) and  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  t h e s e d i f f e r e n c e s , t h e Task Force  saving  of  only  period.  Two-thirds o f the generation same  one  percent  at  the  one  y e a r , w h i l e one p r o j e c t  in  projects  has a two y e a r  conditions  average c o s t approval  rises  (the d r i e s t from  18.1 t o  d a t e s do n o t c h a n g e s i n c e  this  o n l y by  difference.  results Table  mills  planning  a  approved  differ  from  changing  3 shows t h a t  f i v e years i n recorded 20.4  over  (16) a r e  t i m e u n d e r b o t h r u n s . Seven o t h e r s  assumption about water c o n d i t i o n s .  critical  effects  average u n i t c o s t s  A n o t h e r v a r i a t i o n on t h e base c a s e the  plan  per  KWH.  under  history), Project  i s done on t h e b a s i s  82  of  critical  expensive Burrard  conditions.  thermal plant  expensive gas Hence  the  However, l e s s water means more use  facilities.  operates  at  t u r b i n e s are  13  percent  Under  these  capacity also  in  most  reguired  increase  in  conditions,  to  years  average  the  and  produce  of  the  energy.  c o s t during  this  period. The If  f i n a l assumption to be a l t e r e d i s that of f u e l  n a t u r a l gas  {rather 18.1  and  c o a l are p r i c e d at t h e i r estimated  than t h e i r o p p o r t u n i t y  to  17.3  m i l l s per  during c r i t i c a l  KWH.  v a l u e ) , average c o s t s  prices. 1976  cost  fall  from  T h i s drop would be more n o t i c e a b l e  water c o n d i t i o n s  when  the  thermal  plants  are  r e l i e d upon more h e a v i l y .  5.2.3  Interpretation Having  per  KWH  e s t a b l i s h e d the b a s i c s t a b i l i t y of the average c o s t  over  the  1976-1990  v a r i a t i o n s i n the underlying in  more  detail  the  period  to  assumptions, we  relative  several  important  turn now  t o examine  changes i n the component c o s t s .  Table 4 summarizes the i n c r e a s e s i n the base case costs  between  1976  and  1990.  Column 4 presents  v a r i o u s c a t e g o r i e s of r e a l c o s t s during final  column  number of  the  kilowatt-hours.  the show  assumption  while  shows these changes r e l a t i v e t o the change i n the  increase i n variable costs  taxes  and  the changes i n  t h i s period,  l o o k i n g f i r s t at the annual operating  with  quantity  swing  toward  a  relatively  about  (mainly thermal  a greater  fuel)  c o s t s , we see a sharp which  generation  moderate  increase  is  consistent  facilities.  School  reflecting  share of the a u t h o r i t y ' s  an  facilities  TABLE 4  RELATIVE COST CHANGES: (1) 1976 (MWT  (2) 1990 (NOMINAL MM$)  1976-1990  (3) 1990 (1976 MM $ )  (4) 1990 COSTS ( 7 6 $ ) 1976 COSTS"! 7 6 $ ) (3)/(l)  (5) COST CHANGE R E L A T I V E TO QUANTITY CHANGE (4)/3.6  C A P I T A L CHARGES NET  INTEREST  DEPRECIATION . NET  INCOME  214  1262  530  2.5  .69  72  506  213  3.0  .83  0  379  159  835  351  18.8  823  346  2.8  253  106  5.0  1.4  1.0  OPERATING CHARGES VARIABLE FIXED  123  SCHOOL TAXES GRANTS TAXES  18.7  21.2  5.2 .78  & LAND  WATER FEES TOTAL COSTS PRODUCTION (MM KWH)  4.4  39.4  16.5  3.7  9  48  20  2.2  463  4145  1741  3.8  1.1  25,102  91,109  3.6  1.0  .61  84  being  subject  land  taxes  increase  production. reduction The  Water  costs  plus  those  facilities.  This  latter  coefficient  to the r e a l  facilities.  This  new  to  the  costs  figure  is  of  1975  associated  with  increase  expenditures.  level  of  fixed  associated  with a d d i t i o n a l  determined  by  applying types  a  o f new  by t h e much g r e a t e r  these  the  facilities.  relative  t h e b a s i c mix o f t h e s y s t e m  non-generating  general  real  move t o w a r d s l e s s c a p i t a l - i n t e n s i v e  costs  types  as  fixed  i n c r e a s e s over time t o r e f l e c t  operating  assuming  of  and  c a p i t a l cost of the various  p l a n t s i s more t h a n o f f s e t  costs,  terms)  administration  generation  to  rate  a s would be e x p e c t e d , show a  (in relative  adding  c h a n g e s . , The  would t e n d  same  and i n t e r i m r e p l a c e m e n t  coefficient  factors  the  and.  1  some comment. T h e s e c o s t s c o n s i s t o f  insurance by  at  'grants  of costs.  maintenance,  costs  cost  share  deserves  They a r e d e t e r m i n e d operating  terms  fees,  reduction  operating,  labour  real  licence  moderate  expenses  in  i n their relative  operating fixed  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  facilities  fixed  T h e s e two  share  of  these  between t h e v a r i o u s  remained  approximately  constant. The  relative  reduction  contained  i n t h e Task  suggests  the  relatively  unexploited  evolution  fewer  Alternatively,  Force  of  Report  of  these  i t could  that r e s u l t s from (and  signal  the  the f i g u r e s  subseguent  technology factors  using  interviews)  towards t h a t r e q u i r i n g  ( i n an  economic  existence  economies o f s c a l e which w i l l  of  be r e a l i z e d  sense). currently with  the  85  anticipated On terms  expansion.  5 9  balance, annual o p e r a t i n g  c o s t s show an i n c r e a s e i n r e a l  compared to the change i n output. C a p i t a l charges, on  other  hand, e x h i b i t the opposite  consists  of  the  amount  t r e n d . The  that was  depreciation  charge  l e v i e d on f a c i l i t i e s i n  plus the i n v e r s e of the expected l i f e of new  facilities  1975  applied  to the h i s t o r i c d o l l a r c o s t of these f a c i l i t i e s . D e p r e c i a t i o n the  eguipment  in  service  i n 1975  remains constant  examination.  being placed terms.  Similarly,  i n s e r v i c e p r i o r to 1990  Contributing  thermal generating generated,  the annual charge on  a  to  this  trend  will is  period  facilities  also decline i n  capital  per  hence higher  c o s t s , drop f a i r l y  year  substantially relative  p r i o r t o 1976  plus  gross  that  interest  will  outstanding  i n 1990,  and  still  increase  in  r e a l d o l l a r s during t h i s  period. on  the  outstanding  debt  will  the i n t e r e s t payments thereon,  i n nominal terms, w i l l  charges  be  of the pre-1976  while remaining constant  Interest  the  on post-75 debt l e s s i n t e r e s t  during c o n s t r u c t i o n . Some two-thirds remain  to  total  t h i s p e r i o d . These charges c o n s i s t of i n t e r e s t on  the debt issued each  KWH  r a t e of d e p r e c i a t i o n .  Net i n t e r e s t charges, the l a r g e s t component of annual  during  new  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  s e r v i c e l i f e and  output  real  the f a c t t h a t the  plant requires l e s s i n i t i a l  on  i n nominal  terms, l e a d i n g t o a sharp d e c l i n e i n r e a l terms over the under  the  debt  f a l l rapidly  i s s u e d subsequent to  in  1975  On the other hand, i t could i n d i c a t e an underestimation of these c o e f f i c i e n t s or an o v e r e s t i m a t i o n by the author of the f i x e d c o s t s ( r e l a t i v e to the v a r i a b l e c o s t s ) i n the i n i t i a l year of the s i m u l a t i o n . 5 9  86  depends on rate.  In  only  1.8  the  the  quantity  period  times  o f s u c h d e b t and  1976-1990, g r o s s  in  real  terms  the  associated interest  outstanding  (see  Table  debt  increases  2). This  relatively  moderate i n c r e a s e r e s u l t s f r o m s e v e r a l f a c t o r s . projects scale  are  in  l e s s c a p i t a l - i n t e n s i v e and  downstream  less capital internally  spending  debt  in real  This l a s t interest  in  reflected  i n an  percent relative  dollars  leads  increase  i n 1990.  period  net  of  an  of  interest  effect  reduction  in  real  indicated  in  Table  generated  measurement  by  the  fact  that  inflation.  The  interest  payments  5.4  percent  rates  is  relative  to  in  1976  of these c o n f l i c t i n g  net  of  to i t s c o n t i n u a l  about  nominal  from  of  inflation.  expectation in  are  the  i s somewhat o f f s e t  of net  debt  The  funds  historic a  economies  in proportionally  And  contained  outstanding  result  profits.  consideration  premium  could  f u t u r e . More  terms d u r i n g  generating  unexploited  income o r  rates incorporate  inflation  gross  i n the  through net  outstanding decline  facilities  New  interest  to  7.4  forces i s a  charges  over  this  period. As  accounting real  technigues  c o s t s per  consistent  with  justification structure. distortions  KWH  B.C.  for their  inherent  our  i n d i c a t e s an  between  This  2,  1976  Hydro's long  section  model u s i n g  essentially  of  stable pattern  and  1990.  own  forecasting  term g o a l the  of paper  i n t h i s accounting  conventional  6 0  This  result and  flattening has  is the  indicated  framework d u r i n g  in is the  rate the  periods  T h i s r e s u l t i s c l e a r l y d e p e n d e n t upon a s s u m p t i o n s 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 future general price 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 t h a n i n d i c a t e d . 6 0  87  of i n f l a t i o n . weaknesses  In e a r l i e r  in  using  chapter pointed  this  methodology  establishing  a rate structure.  results  of  the  economic  c o s t s o f t h e B.C. H y d r o  approach  out  We  as  turn  designed  other a  now  to  fundamental  sole to  basis f o r  look  determine  at  the  the marginal  system.  5.3 D e t e r m i n a t i o n Of M a r g i n a l C o s t  5.3.1  Base In  Case  this section  analysis  of  the  order to i s o l a t e from  energy  shock.  we  present  impact  the cost  demand,  off-peak  results  effect  o f changes  both two The  identical  the  periods only  shock  has  and d o e s  runs i s a t t r i b u t a b l e s o l e l y also  l a r g e customers the  t o t h a t o f the system's  peak and o f f - p e a k demand. The c o s t  model  smallest  an  distinct  f o r a given energy an  impact  not a l t e r  on  B.C.  the  Hydro's  t h e change has a l o a d  average, thus differential  t o t h e change  d i s t i n g u i s h e s between  in  the c o s t  affecting  between t h e  peak  changes  t a k i n g power a t t h e s u b - t r a n s m i s s i o n customers  economic  i n peak as  two r u n s a r e p e r f o r m e d  a n n u a l peak demand. The o t h e r assumes t h a t factor  of  on c o s t s o f v a r i o u s demand s h o c k s . I n  One r u n assumes t h a t  system's  the  who a l s o r e g u i r e t h e f u l l  demand. f o r the  level  and  distribution  system. Because mechanical variety 10  of the d i s c o n t i n u i t i e s project  approval  likely  process  as a  used  o f l o n g - t e r m demand s h o c k s a r e t e s t e d .  million  KWH  a year  result  in  this  They  (.04 p e r c e n t o f p r e s e n t e n e r g y  of  the  model, a  range  from  demand) t o  88  5 billion  KWH  annually  {19.9 p e r c e n t )  decrease  in  demand.  In t h e s h o r t r u n , these  accommodated  by v a r y i n g t h e amount t h a t e a c h  In t h e l o n g e r term, t h e investment fit  t h e new The  demand  standard  simulations that  also at  for  same  in  the  B.C.  export  level  period.  The demand s h o c k  number  of  electrical  these  In  the  next  demand s h o c k s . system  the  for  and  is  i s actually  case  assumption  economically available.  1976  We  continues  the duration of the simulation  does n o t c o n s i s t customers  o f any c h a n g e s i n  served  the  by B.C. H y d r o . T h i s i s  in  the  we r e v i e w  the r e s u l t s  1975  Task  the impact  Force  of altering  The f i r s t  load  factor  of the i n t r o d u c t i o n  column i n d i c a t e s  the  t h e 55 y e a r  the discounted smallest  and  simulation period r e l a t i v e  present  customers  of various  size,  direction  o f t h e p e r t u r b a t i o n . The n e x t  demand s h o c k . Columns 4 and 5 p r e s e n t in  that  d i s c o u n t e d p r e s e n t v a l u e o f the energy  over  used.  to best  i n t h e p r e v i o u s base  market  t o serve  section,  is  assumptions. Table 5 presents  and  facility  This includes the  assumed t o grow a t t h e r a t e i n d i c a t e d Report.  and  demand s h o c k s a r e  t h e demand s h o c k i n t r o d u c e d i n  fixed  increase  6 1  effect.  Hydro  an  programme i s a d j u s t e d  assumptions o u t l i n e d  of  assume t h a t the  projections.  continue  one-half  attractive  f o r both  peak  generation  to t h a t without the  the increase  value  ( i n 1976 d o l l a r s )  over  this  period  two show  or  decrease  t o the largest  resulting  from the  c h a n g e s i n demand. The  final  f o u r columns c o n v e r t  this  information  into  1976  I f demand r i s e s a b o v e t h e Task F o r c e ' 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 e n e r g y d e f i c i t s w h i l e new gas t u r b i n e s s u p p l y any p e a k i n g s h o r t a g e . 6 1  TABLE 5  GO MARGINAL ECONOMIC COSTS FOR VARIOUS DEMAND SHOCKS  DEMAND SHOCK (MM. i r a )  SYSTEM LOAD FACTOR OF SHOCK  BASE CASE  P.V. ENERGY GENERATED (Mil KWH)  1,393,223.0  P.V. PEAK GENERATED (M W)  249335.. 1  P.V. LARGE CUSTOMER COSTS  (MM 76$)  P.V. SMALL CUSTOMI COSTS  (MM 76?  16699.2  20738.7  -10  63.5%  -198.0  -39.4  -4.2  -4.7  -10  off-peak  -198.0  0.0  -3.9  -4.1  -585.4  -589.8  0.0  -565.1  -567.4  -100  63. 5%  -5255.0  -397.5  - 100  off-peak  -1000  63.5%  -27,114.0  -39S6.8  -727.5I  -771.8  -1000  off-peak  -27,114.0  0.0  -577.6  -599.2  -3000  63.5%  -67,750.0  -1851. 3  -1984.1  -3000  off-peak  -67,750.0  -1530.2  -1595.1  -2441/5  -2662.9  -2060.5  -2168.7  -5000 -5000  63. 5% off-peak  -5129.0  -107,422.0 -107,422.0  -11,963.,1 0.0 -19,941..8 0.0  +10  63.5%  195.0  42..2  4.2  4.7  +10  off-peak  195.0  0..0  3.9  4.1  +100  63.5%  1979.0  400. ,5  + 100  off-peak  1979.0  +1000  63,5%  +1000  42. 3 •  46.7  0.,0  38. 7  40.8  16,994.0  3989..5  -165. 7  -121.5  off-peak  16,994.0  0..0  -236. 2  -214.6  +3000  63.5%  60,795.0  11,965. 5  1206. 9  1339.6  +3000  off-peak  60,671.0  0.,0  1046. 1  1111.0  +5000  - 63.5%  101,668.0  19,945..6  2060. 8  2282.1  +5000  off-peak  101,668.0  0..0  1572. 0  1680.1  AVERAGE:  AVERAGE MARGINAL ENERGY AND CAPACITY COST FOR ENTIRE SYSTEM:  LARGE  CUSTOMERS  SMALL CUSTOMEP.S  ENERGY COST 76$ MILLS/KWH)  CAPACITY COST (76$ MILLS/KWH)  (76$ MILLS/KWH)  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  ENERGY COST  CAPACITY COST (76S MILLS/K'iVK)  90  mills  per  KWH.  Column 6 i s o b t a i n e d  column 4 by t h o s e is  derived  from  63.5  cost  i n mills  percent.  The  p e r KWH  last  two  shock.  Column  resulting  i t by t h e g u a n t i t y  i n column  the  change  in  u n d e r an assumed l o a d columns  f o r the s m a l l customer  7  i n column 4  i s the c o s t a t t r i b u t a b l e to  expressed  calculation in  the incremental  t h e on-peak s h o c k and d i v i d i n g  demand of  i n column 2 f o r t h e o f f - p e a k  by t a k i n g  2. The r e s u l t  by d i v i d i n g t h e r e s u l t s o f  using  perform  a  peak  factor similar  t h e c o s t f i g u r e s shown  column 5. The  results  shown i n T a b l e  5 merit  some comment.  the c h a n g e i n t h e g u a n t i t y o f e n e r g y g e n e r a t e d the  load  f a c t o r o f t h e demand  c h a n g e s , however, t h e r e  shock.  are small  For  Generally,  i s independent o f  two  of  the  d i f f e r e n c e s c a u s e d by  demand altering  the  load f a c t o r assumption. A c l o s e r examination o f the workings  of  the  projects have  an  either  model  designed energy  exported  thereby  lack  or  is  generated  consistency  examination,  by  using  triggered  in  cut  in this  this  the  which  project  calculations,  projects.  last  four  notable  model and  columns  exceptions.  the  the last far  show Upon  from the  distortions  g r o w t h . The b a s i c  i n 1990 t o meet a s m a l l  operates  also  i s then  o f S i t e C w h i c h , under t h e base  f o r commencement  new  energy  o f f d a t e f o r demand  e n e r g y d e f i c i e n c y . As 1990 r e p r e s e n t s growth,  trigger  energy c a p a b i l i t y  the two  but  anomalies appear t o r e s u l t  inherent a  in  with  these  problem c o n c e r n s t h e r o l e is  T h i s new  included  peak demands  capacity  t h e s t a r t o f new e n e r g y  of fine tuning  caused  the different  p r i m a r i l y to supply  results  considerable  that  component.  delaying  The  closer  reveal  year below  of  case,  forecast demand  i t s energy  91  capability,  a s i t u a t i o n only  partly mitigated  export  market c o n d i t i o n s . T h u s ,  o f -100  million  large the  cost  the  case  of  The columns  with  1000  the  million  r e s u l t s of the  the  average  $18.00 and  Sensitivity In  order  variations alternative introduced  averaging.  decision  the  The  some  of  were  shocks  63.5  percent  projected with  reduction  artifically  projects  i s not  in  large  this reduction.  Site C  table for  just  use  In are  reguired  cost  reduction  the  last  i n the  discussed  of a v a r i e t y of  minimize  i n the  9 f o r the  four  column. are  not  sizes  and  distortions  followed  f a c t o r , are  the  the  the  simulations demand  and  caused  model.  capacity  The  cost,  approximately equal  to  respectively.  Analysis  d i r e c t i o n s u n d e r an  compared  load  to understand  in  reguired  to the  observations  rules  kilowatt,  both  be  of  anomalous runs  $26.00 per  shock  increase.  mean o f t h e  percent  assumed  demand  shock, thermal  f i g u r e s shown i n c o l u m n s 7 and a 63.5  longer  the  i n 1990  o f demand s h o c k s s h o u l d  arbitrary  assuming  5.3.2  this  Hence  the  This i s r e f l e c t e d i n the  bottom  the two  no  relative  KWH  r e s u l t that  demand  represent  c a s e of  shown to r e s u l t from  f i g u r e s at the  directions by  KWH  the  in  is  energy generated.  from t h e  included  project  experienced  i s never t r i g g e r e d .  resulting  The  of  are  i n m i l l s per  accelerated and  this  savings  guantity  savings  KWH,  i n the  under the  of  sensitivity underlying  10,  1000  system.  combined  these r e s u l t s  assumptions,  performed.  assumed l o a d  f o r the  of  These  and  to  several  alternatives KWH  in  f a c t o r coinciding with  the  As  energy  5000 m i l l i o n  such, the and  results  capacity  can  average  92  marginal cost  o f 22.6 m i l l s p e r KWH  We f i r s t export  alter  market  This enables allowing  the f r a c t i o n  available a  smoother  t h e e x p o r t market  reaction  to  demand  shocks  by  t o absorb  more o f t h e d i f f e r e n c e .  The  23.6 m i l l s  p e r KWH  the  introduction  average KWH.  a short-term average projected  rises  slightly  o f the shock marginal cost  mills from  per  KWH  5000  million  mills  p e r KWH  reduction  KWH,  forecasted  we  the  new c u s t o m e r s  results energy  with i t s  marginal  savings  impact  assumed  peak demand  no c h a n g e i n t h e f o r e c a s t  to  system.  permanently  We  now  alters  cost  of  shock  possible  23.8  of  through  energy.  on c o s t s o f a l t e r i n g t h e to  be  for  served cost  two  by  customer  which,  increment  B.C.  o f changes i n  number o f c u s t o m e r s  fixed  annual  1976 s h o c k o f  generated  i n t r o d u c e a shock by a  year  m a r g i n a l c o s t o f 16.5  i n T a b l e 5 show t h e u n i t  and/or  that  of  t o begin g e n e r a t i n g energy  o f the minimal  examine  yields  The amount  The l a r g e  t o an a v e r a g e  assuming  1976,  KWH.  i n t h e amount o f h y d r o - e l e c t r i c  The  the  a s compared  t h e need  l e d only  because  number o f s m a l l Hydro.  t h e y e a r 1976  gas t u r b i n e s . C o n v e r s e l y , t h e 1976 KWH  Finally,  delaying  1976 t o 1980, t h e  o f 20.7 m i l l s .  i n an a v e r a g e  reflecting  becomes  22.6 t o 22.9 m i l l s p e r  f o r only  o f 5520 m i l l i o n  resulted  KWH,  the c o s t l y  from  By  f o r generation i n the Burrard plant  capability  5000 m i l l i o n  customers  assumption.  was a p p r o x i m a t e l y 1000 m i l l i o n energy  for the large  o f t h e permanent change f r o m  The i n t r o d u c t i o n  energy  this  the  t h e t i m i n g o f t h e demand s h o c k .  marginal cost  attractive  50 t o 100 p e r c e n t .  average marginal cost  We n e x t a l t e r  of the economically  t o B.C. Hydro from  resulting  under  f o r large customers. ,  classes connected  beginning i n  the  number  of  93  small  connected  customers  demand f o r e c a s t s . The annual  without  the  i n i t i a l connection charges  electrical  plus subseguent  s e r v i c e c o s t s i n d i c a t e an approximate average annual  a s s o c i a t e d with connecting a new  5.3.3  and  affecting  s m a l l customer of $ 6 0 . 0 0 .  cost 62  Interpretation We  turn now  to an i n t e r p r e t a t i o n of the r e s u l t s i n Table  a  comparison of them with the f i g u r e s generated  t h i s chapter. From the o u t s e t , i t i s important  earlier in  to recognize t h a t  the numbers shown are not to be taken as a c c u r a t e t o decimal  point,  but  rather  represent  5  the  final  an approximation  of the  r e l e v a n t marginal economic c o s t s . Perhaps the most i n t e r e s t i n g r e s u l t r e v e a l e d i n Table 5 the  heavy  predominance  of  the  energy  over  component of marginal c o s t s . For the l a r g e percent  of  the  incremental  factor  of  63.5  percent)  the peak demand  customers,  c o s t s a s s o c i a t e d with a  e l e c t r i c a l demand change (corresponding  to  the  at  met  85  long-term load  are a s s o c i a t e d with the change i n the  f o r the e n e r g y - c r i t i c a l B.C.  energy demand i s f i r s t  over  system's  energy component of the l o a d . T h i s i s c o n s i s t e n t with that  is  the  fact  Hydro system, a change i n the  by a l t e r i n g the g u a n t i t y of f u e l used  the Burrard p l a n t and then by v a r y i n g the s t a r t i n g  dates  of  major generation and t r a n s m i s s i o n p r o j e c t s . Changes immediately existence  in  peak  demand,  on  the  other  hand,  a f f e c t the generation p l a n n i n g programme due of  excess  reserve  capacity,  although  do  not  to  the  a permanent  This f i g u r e should be viewed with considerable caution as there i s an inadeguate amount of p u b l i c l y a v a i l a b l e data to estimate these c o s t s with much c o n f i d e n c e . 6 2  9a  alteration only  will  eventually  projects.  reguire  no  discounted felt  however,  new a s s o c i a t e d  when v i e w e d f r o m  in  compared  with  Immediate  on  t h e major  expenses. Another  interesting  result  from t h e l a r g e s t and s m a l l e s t  fact  that  i n energy  either  adjustment  small  transmission  this  analysis  associated  change  w i t h demand  customers. I n  will  shocks  results  from t h e t h e same  transmission  that  coincident  "miscellaneous  and i s t w i c e  that  greater  peak demand o f t h e  additional  adjustment  distribution  facilities  results  of  plant"  i s energy  customers as  f o r large.  associated smaller  with changes i n t h e  customers  downstream  reflects  transformation  the and  t h a t w o u l d be e n t a i l e d .  o f the marginal cost  t o be q u i t e c o n s i s t e n t costs  in  electric  f o r small  costs  difference  line  between t h e two c u s t o m e r c l a s s e s i s t h e a s s u m p t i o n in  slight  the  t h e case  reguire  and a s s o c i a t e d  reason f o r the  i s  this  relatively  economic  but these a r e  in  responsive  The  of  i n the generation  investment  The  sub-  demand, t h e s i m i l a r i t y  source  programme. T h e o n l y category  costs  of  emanating  change  be  6 3  of the incremental  a  will  transmission,  and a s s o c i a t e d  proximity  of  and must be  responses  facilities,  t h e major g e n e r a t i o n  inexpensive,  facilities,  1976.  and t r a n s f o r m a t i o n  o f new c a p a c i t y -  are relatively  transmission  t h e investment  transmission  line  These,  influence the timing  a n a l y s i s would a l s o  with those o f Table  various  generation  1  reporting  projects.  After  appear on t h e  removing  The s u g g e s t e d 15-85 demand-energy s p l i t f o r l a r g e customers i n t h e e n e r g y c r i t i c a l B.C. Hydro s y s t e m a p p e a r s c o n s i s t e n t w i t h the finding that the relevant demand-energy s p l i t f o r l a r g e c u s t o m e r s i n t h e 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 f r o m 50-50 t o 35-65. ( O n t a r i o H y d r o , 1976, V o l . 1,17) 6 3  95  the c o s t s a s s o c i a t e d analysis  in  this  with " m i s c e l l a n e o u s investment p l a n t " ,  s e c t i o n i n d i c a t e s an average marginal energy  c o s t f o r a l l customers of  18.5  m i l l s per KWH.  a s h o r t run marginal energy c o s t of energy at B u r r a r d .  18.7  from  In the longer run, d i s r e g a r d i n g  the  subsequent energy producing p r o j e c t s w i l l c o s t The  capacity  related  reasonable. Table 1  suggests  (excluding  gas  turbines)  k i l o w a t t . T h i s compares with $18.00  and  $26.00  component the are  costs  associated  transformation  and  $7.00  also  $15.00  estimates  of  with  the  relevant  distribution  additional  peak-related  downstream  transmission,  facilities. c o s t s of Table  i n the p e r i o d  former  m i l l s f o r the system as a whole. The  methodology  assumptions u n d e r l y i n g  two  r e s u l t s i s q u i t e d i f f e r e n t and  why  the numbers should  be s i m i l a r . Nevertheless,  t o b e l i e v e t h a t the two  'a p r i o r i there  f i g u r e s are, i n f a c t ,  the  purpose,  the d e r i v a t i o n of  there i s no  2  increase  1976-1990, while  l a t t e r average 24  reason  a  f o r l a r g e and s m a l l customers r e s p e c t i v e l y .  t o 19 m i l l s per KWH  and  seems  projects  and  cost  with the marginal economic c o s t s of Table 5. The 18  while mills.  peaking  L a s t l y , we compare the average accounting  from  diversion  17-19  costs  of  marginal  d i f f e r e n c e i s accounted f o r by the  costs  of  between  the  generating  14 m i l l s per KWH  6  The  T h i s compares with  mills  p r o j e c t s , * Revelstoke energy i s to c o s t all  the  1  is  these reason some  reasonably  consistent. * The d i v e r s i o n p r o j e c t s should not be considered as marginal sources o f enerqy. They are r e l a t i v e l y small and low cost, and are now being c o n s t r a i n e d by non-economic c o n s i d e r a t i o n s . These p r o j e c t s are likely t o be brought on stream as soon as institutionally p o s s i b l e , and at l e a s t i n the case of the Kootenay River D i v e r s i o n , r e g a r d l e s s of the energy supply-demand balance. 6  96  The costs  T a b l e 2 r e s u l t s are  expressed  increase  m i l l s per  i n these average costs  marginal slight  i n 1976  accounting  increase  relatively  costs  i s in  inexpensive  for  average accounting to  suggesting be  average c o s t s .  fall  further that  conclude  economic c o s t s intuitive system, the  this  presented  real the  c a l c u l a t e d i n the  and  a p p l i c a t i o n and  existence  this  period  of a  slight that  average accounting  costs.  This  the  of  construction  unit  several  diversion projects  older  terms d u r i n g cost  tendency  capital-intensive  periods of  which  new  of  inflation,  projects  must  costs. by  i n Table of  the  previous  accounting  suggests  of the  real  economic c o s t i n g 1,  marginal,  I t i s a l s o i n s p i t e of the  section  understanding  shown i n T a b l e  during  of  cost  above a v e r a g e a c c o u n t i n g We  the  in  The  "non-iarginal"  lower  projects  KWH.  exceed  spite  tend to the  average, not  the of  noting  5  seem  that  consistent  operation  p o s s i b l e new  average  section.  i m p l i c a t i o n s of  We  of  the  turn  marginal with  B.C.  generation  system now  the  these marginal  Hydro  projects  accounting our  an  costs  attention costs.  to  97  6-. APPLICATIONS In  this  derived Hydro  i n Chapter system  application stucture The  chapter,  of  study  the  this  c h a n g e . The  i n g e n e r a l and the  from  6.J. Rate S t r u c t u r e  such  a  marginal economic c o s t s  implications first to  as  for  section  the  the  of  a  t o B.C.  on s y s t e m e x p a n s i o n be  B.C.  discusses  design  i t could apply  impact  r a t e s t r u c t u r e can  various results  determined,  and  the rate  Hydro.  and  costs  presents  restructuring.  Design  General The  fundamental  efficient and  the  5 and  e x p l a i n s how  of a reformed  6.1.1  apply  o f economic p r i n c i p l e s  - both  second  we  in  d e s i g n i n g an  r a t e s t r u c t u r e i s to equate  cost,  averaqe  objective  while  keeping  accounting  residential  rate  cost.  average Figure  structure.  A  marginal  economic  accounting 1  price  represents  rate of y  cents  pays  the  "L"  to egual marqinal marginal desiqned (revenue)  total b i l l  indicated  by  shaded  the a c c o u n t i n q c o s t s i n c u r r e d economic c o s t i s found rate should to  ensure  equals  be  t o be  to  t h e shaded  the  equal  a  to  typical  area  and  beneath  *'L". I n t h i s  per  KWH  and  which i s assumed  serve  z cents  set equal to t h i s  that  price  customer consuming x k i l o w a t t -  h o u r s p e r month f a c e s a m a r g i n a l a  economically-  him.  per KWH,  If  the  then  the  the r a t e s t r u c t u r e the  rate  s i m p l e example, a  curve flat  Y6  FIGURE 1  • /KWH -7?-  C  B  D  T I  E_  X  KWH/MO  99  rate  of z c e n t s  conditions  ABCD= DEFG  Those  tend  a p p r o a c h . The the  who  bill  the  implies  to  a  the  both  ABESHI=CFHI.  are  the  satisfy  not  as  economic  multi-part  or  The  easily  efficiency multi-block  l e a s t p r i c e s e n s i t i v e component customer o r f i x e d charge)  r e v e n u e o b j e c t i v e . The  bounds o f  accounting  firm  ( u s u a l l y the  rate  would  criteria  either  former adjusts  m a r g i n a l " consumption  latter  (a c e n t s  per  modifies  KWH  in  the  Figure  c u s t o m e r ' s consumer s u r p l u s ,  so  as  "intra-  1),  to a g a i n  within  meet  the  condition.  Others  abandon  allowing  the  economic  cost.  elasticity  the  marginal This  rule"  strict price  may  whereby  straight  "across  consistent  the  deviate  done on  the  p r o p o r t i o n a l to the  economic e f f i c i e n c y  to  be  inversely  t o be  which  hold  to support  total  t o meet t h e  the  f o r a l l consumption  a r i s e s when t h e s e two  reconciled.  of  KWH  since  difficulty  criterion  per  from  the  amount  basis  of  the  the  revenue  "inverse  deviation  is  Alternatively, a  board" adjustment i n marginal  with  marginal  of the  the  price elasticity.  objective,  reguirement  p r i c e s so is  as  sometimes  recommended. We  turn  to suggest structure.  now  to  examine t h e  factors We  shall  to seek  be  incorporated  not  to  of  m a r q i n a l economic c o s t s  the  fundamental o b j e c t i v e  6.1.2  B.C. In  the  and  deviate  c a s e o f B.C. in  an  from t h e  p r i c e s i n our  o u t l i n e d at the  Hydro  optimal strict  attempt  to  and rate  equating satisfy  outset.  Hydro  suggesting  marginal  specific  an  appropriate  economic  costs  rate  structure,  calculated  i n the  we  shall  last  use  chapter.  100  Average e x i s t i n g p r i c e s represent  the  appropriate  Residential factor  of  of the the  amount o f  per  this  reduced  capacity  KWH  load  50  This  consumed.  factor.  cents  additional customer  existing  priced i n i t i a l  rate  of  1.8  cents  per  KWH  B u l k c u s t o m e r s , on  (in the and  to  6 5  on  load  the  order  basis  to  use  upwards the  customers  26 cost  6 7  mills of  to  block  per  4.6  reflect  KWH  could  followed  and This  KWH.  s t r u c t u r e would units  is in  KWH.  m i l l s per  all  per  This  28  rate  for  cents  of be  energy obtained  contrast by  a  be  to  the  1977  marginal  with  separate  1976$).  other  charges f o r t h e i r  energy  have a c o i n c i d e n t  load f a c t o r of  Table  is  charge.  In  6 6  must a d j u s t  KWH  .2  taken  coincident  billed  period.  appropriate  per  be  r e s u l t i n g combined e n e r g y  cost  the  a  are  small  The  through a s m a l l high  we  average accounting  o f 2.6 The  5,  will  costs.  have and  each  charge f o r  suggests that  rate  percent  Table  m a r g i n a l economic an  a class  t h e y use  in  capacity  compares w i t h  a flat  and  energy  shown  mills  average accounting  c u s t o m e r s as  between 45  figures  i n each customer c l a s s  hand, are  billed  peak r e q u i r e m e n t s . As approximately  5 i n d i c a t e s that they should  face  82  a c l a s s , they percent.  a m a r g i n a l energy  6  8  charge  as m e n t i o n e d i n C h a p t e r 2, B.C. Hydro a c c o u n t s s u g g e s t t h a t each customer class is now generating revenue which approximately meets the a c c o u n t i n g c o s t s a t t r i b u t e d to i t . In t h i s p a p e r , we w i l l accept the present a l l o c a t i o n of costs between customer classes. a strong argument can be made, however, t h a t t h e c o s t a l l o c a t i o n m e t h o d o l o g y , with its heavy emphasis on t h e c a p a c i t y component, u n d e r c h a r g e s c u s t o m e r s w i t h high l o a d f a c t o r s . T h i s l o a d f a c t o r a p p e a r s t o be r e l a t i v e l y c o n s t a n t 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 . Unlike the present situation, this customer charge could reflect cost 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 c u s t o m e r t y p e s and densities. T h i s i s a l s o r e l a t i v e l y i n d e p e n d e n t of the q u a n t i t y consumed. 6 5  6 6  6 7  6 8  10 1  of  19  per  KWH  m i l l s and  ($18.00 per  mills  per Our  rate  KWH.  charge of  KW)  present,  charged  schedule a  One  way  marginal  average  of  rates  at  historical  equivalent  p r i c e of approximately  10  and  of  In  addition  split,  capacity  traditional  the  7 0  the  r a t e i s more for  dilemma  on  the the  considerations.  with  initial  restructuring  demand-energy  the  this  would  be  to  charge  the  r a t e s f o r a l l l e v e l s of consumption  a n n u a l c r e d i t on  they  the  6  meet r e v e n u e r e g u i r e m e n t s  to  two  flat  reference be  level  the  of  case  of g e n e r a l  charqes  should  to the  present  the  basis  point.  returned  would f a c e  changes i n t h e i r  capacity  to  b e n e f i t s would  time  the  m a r g i n a l energy  the  as  an  an  4  mills and  substantial  of  rise  to deal  then p r o v i d e  they are  customer c l a s s i s i n o r d e r .  required  gives  reconciliation  In  an  reversal  recommended  This  level  for  for this  dramatic  class.  .At  3  69  than double t h a t  any  marginal capacity  results indicate a  combined  same  adjusted  respectively  mills  to  an  of In  7 1  the  and  consumption  this  way,  the  t o customers while at  appropriate  two  marginal  the  prices for  consumption.  customers,  the  a p p r o x i m a t e 24  combined m i l l s per  average p r i c e f o r the  energy KWH.  c l a s s , so  and  This that  is a  The peak c h a r g e now i n e f f e c t and t h a t recommended are not directly comparable. It is c u r r e n t l y b a s e d on t h e c u s t o m e r ' s non-coincident peak, while we suggest that i t should be determined largely on the b a s i s of the degree o f c o i n c i d e n c e w i t h the s y s t e m ' s peak. T h i s i s t h e term used i n t h e electric utility industry to refer to the split between t h e peak and e n e r g y components o f e l e c t r i c a l demand. , New large customers could also be g i v e n a r i g h t t o the r e v e n u e 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 similar annual credit based on what a c o m p a r a b l e f i r m consumed a t t h e 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 c u s t o m e r ' s c l a i m on e a c h y e a r ' s s u r p l u s . 6 9  7 0  7 1  102  new  flat  rate at  reconcile the  the  level  e c o n o m i c and  c l a s s , i t would i n v o l v e  large  number  number o f  enter  of  are  i n t o the  a  are  relevant  kilowatt-hour capability  to  i n the  by  the  to  the  meet  with the  7 3  same  that  more i m p o r t a n t relatively  will  minimum. not  period.  the  the small  which  could  structure.  Many  rates. This  as  the  one  used  energy 5  p.m.  plants  are  downstream f a c i l i t i e s  v a r i a t i o n s may  than  at  step  having  yield  would  be  when i t its  is  where a  annual  petroleum-fired that  factor  Hydro system  time-varying  r a t e , and  easily,  the  Hence  is  are  a to  net make  coincided  determination  winter,  i n the  same t i m e , downstream  one  which c o u l d  seasonal  tariff.  a t i m e when s t r e a m  r e s e r v o i r s must be  empty, once f i l l e d At  for  peak.  Hydro's a n n u a l peak i s i n the a  day  A worthwhile i n i t i a l  s y s t e m ' s peak, r a t h e r  introduced  at  rate  reduces  amount  extent  within  the  considerations  time of  a.m.  bills  to  7 2  appropriate  5  However,  expense of  e n e r g y - c r i t i c a l B.C. at  adjustment  the  charge f o r l a r g e customers g r e a t e s t  independent of t h i s A  an  in  at the  other  some d i u r n a l r a t e  economic b e n e f i t . peak  of  peak demand and  capacity-related,  the  of  users.  little  criteria.  a reduction  considering  consumed  Nevertheless, needed  accounting  customers  number  design  jurisdictions as  small  would r e g u i r e  larger e l e c t r i c i t y  There  not  this  summer,  designed during  facilities  so  must be  B.C.  flow  that  the  be  is  they  winter built  to  A fuller discussion of possible rate structure designs, 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 t h e i m p a c t o f t h e s e c h a n g e s , i s c o n t a i n e d i n A p p e n d i x C. Naturally, any move e n t a i l i n g i n s t a l l a t i o n o f new eguipment t o make t h i s f e a s i b l e s h o u l d o n l y be u n d e r t a k e n i f t h e r e s u l t i n g m a r g i n a l economic b e n e f i t exceeds the m a r g i n a l c o s t i n v o l v e d . 7 2  7 3  103  meet t h e s y s t e m ' s w i n t e r most  likely  to  be  peak, and t h e p e t r o l e u m - f i r e d  required  r e q u i r e m e n t s and t o f u l f i l Sates  which  associated alter  reflected  in this  forecast  annual energy  the higher  seasonal  consumption  s o u r c e w h i c h was l e s s s e a s o n a l l y  tariff  related  approach  with  which v a r i e d a c c o r d i n g  planning  patterns  thermal  sources.  e n c o u r a g e some c u s t o m e r s sources with to t h e i r that  t o meet peak deficiencies.  and o p e r a t i n g  long  term  o r switch  applicability  Higher  customers  taking  introduction  rates  during  the  and d u r a t i o n  indicate  these seasonal  have  dry years  would  proved  t o be  wet y e a r s ,  water  dams  could  be  low  rates  that  of  we  a l t e r n a t i v e energy  o f 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  frequency  As  c a p a b i l i t y when t h i s  advantage  t o an e n e r g y  B.C. H y d r o ' s r e l i a n c e upon  t o b u i l d and u t i l i z e  over  to  t o B.C. Hydro i s a  economic advantage. C o n v e r s e l y , d u r i n g  would have s p i l l e d  customers  t o water c o n d i t i o n s .  storage  costs  sensitive.  seen, t h e d r i e r t h e y e a r , the g r e a t e r expensive  both  w i t h t h e w i n t e r peak would e n a b l e some  their  A  season,  Units are  utilized year.  varying  The  expected  o f i n t e r r u p t i o n might be a u s e f u l way and a n n u a l c o s t  by  to  v a r i a t i o n s to the large  customers. Another c o n s i d e r a t i o n design  of a rate structure  increases would then  which c o u l d  eliminate  e f f e c t few c o s t  associated  i s the cost  and d e c r e a s e s . A l a r g e  initially  with  was a n t i c i p a t e d modifications  be  asymmetry  aggregate  the cost  savings  incorporated  due  reduction  the  in  large  could  be  design  introduced  of  a  rate  which reduced  demand  b u t would  fixed  t h e s y s t e m . I f an a g g r e g a t e d e c r e a s e from t h e i n i t i a l  the  between demand  of f u e l a t Burrard to  in  costs  i n demand structure,  the marginal  104  rate  once a c u s t o m e r had  amount. not  If,  those  the  with  c o n s u m p t i o n and  higher  the  thus slow the  reform.  Given  under c o n s t r u c t i o n introduction cut  of  an  demand below  and  provide  costs.  and  A better  what would be  would  o f a change i n r a t e  so  projects  underway The the  would  timing  of  be  was  maintained  to  which t o c o v e r give  structure  five  of  are  in  rate  currently  the  sudden  fuel  the  output  could costs,  large  fixed  six  years  or  deferred  a reformed  generation  demand.  timing  (or move t h e r e be  their  rate structure  saved at Burrard  carefully  level  stream,  efficient  be t o  certain  chance to a d j u s t  on  approved c o u l d  new  a  demand  hydro p r o j e c t s  a market f o r t h e i r  must be  System  the  coming  i n t r o d u c t i o n of of  Demand And  6.2.1  gradually), while  once  those  completed.  rate structure  projects  are  and  inevitably  orchestrated.  Response  Theory Rate  economic  present  structure efficiency  thus a l t e r  the  the  and  yet  find  approval  intertwined  6.2  not  could  appropriate  new  b a s e from  approach  total  by  of growth i n system  i s the  economically  notice that  rate  be  demand  i n the  rate  that  will  a smaller  his  flexibility  A related consideration structure  back  however, a r e d u c t i o n  expected, then  provide  cut  system  B.C.  existing  reform will  planning,  Hydro l o a d  consistent  affect  the  operation  forecasts  r a t e s t r u c t u r e . Thus,  with  of  demand f o r e l e c t r i c i t y  and  and  The  ultimately, costs.  implicitly we  principles  are  assume no interested  change  in  in  the  105  impact  on  discussed  demand i n the  The  marginal  inputs of  p r i c e and forms.  firm  is will  to the  seek  the  to  constraint available  of  this  limiting  the  weather,  the  own  of  substitute  user,  electricity  assumed  to  seek t o combine  minimize c o s t s  production  derive  for a  function  defining  A  these  given  level  the  most  f a c i n g i t . A consumer, on  the  s a t i s f a c t i o n from  requiring  satisfaction  consumption,  electricity, subject  and  to  and a  quantity  to  budget  of  items  price  of e l e c t r i c i t y  initially  rises,  the  the  i t s consumption  medium t e r m , however, c a p i t a l s t o c k  f a c t o r mix  adjusted.  technology  changed.  the  can seek  be  t e r m , new,  more  be  developed  and  a means t o  t i m e o f t h i s change i n m a r g i n a l p r i c e , due when a l l o t h e r i n p u t  can  long  effect  reform,  We  In  can  structure  be  to r e d u c e  lifestyles  rate  its  to produce i t s o u t p u t .  combination  marginal  electricity-conserving  over  factors  him.  a v a i l a b l e . In and  number o f  industrial  a l i m i t e d number o f p o s s i b i l i t i e s  altered  prices  reguired  facilities  maximize  to  When  use  marginal  availability  an  technical possibilities  hand, i s assumed t o  levels,  and  case of  many i n p u t s  subject  the  d e p e n d s upon a  income  price  i n a manner which  including  are  and  the  maximizing  efficient  only  of  introducing  7  the  In  one  output,  other  of  section. *  population  represents profit  last  costs  demand f o r e l e c t r i c i t y  including  energy  and  prices  guantify solely  and  the to  output  I t s h o u l d be r e i t e r a t e d t h a t we a r e 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 t h a t B.C. Hydro's forecasts 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 s e e k now t o e x a m i n e t h e i m p a c t o f altering rate s t r u c t u r e g i v e n a r a t e l e v e l . I n the l o n g e r t e r m , 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 . 7 4  106  l e v e l s remain The  unchanged.  long  electricity  run  enables  arc  o f t h e demand f o r  I t measures t h e  average  consumed r e l a t i v e t o t h e a v e r a g e change i n  a l l other f a c t o r s  e =  elasticity  us t o do j u s t t h a t .  change i n e l e c t r i c i t y price,  own p r i c e  remaining  ((Q2 - Q1)/(Q1 • Q2)} /  constant.  Algebraically,  { (P2 - P 1 ) / ( P 1 + P 2 ) ) . . . . . . ( 1 2 )  where e than  is  the  or egual  long  r u n a r c own p r i c e  Q2 i s t h e new c o n s u m p t i o n P1 i s t h e o r i g i n a l r e a l P2 i s t h e new r e a l  and u s i n g  Q2 = Q1 * (P1  level;  level after  marginal  marginal  the p r i c e  price.  t h e a b s o l u t e v a l u e o f e,  (P1 + P2 - e *  (P2 - P1}) /  + P2 + e * (P2 - P 1 ) )  marginal  (13)  price  increase  Q1 a s a  result  f r o m P1 t o P2 c a n be  g i v e n an a p p r o p r i a t e v a l u e f o r e and some a s s u m p t i o n adjustment For both  price effect  an i n d i v i d u a l  case,  a  determined about  the  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  is  effects  of a p r i c e  however, s i n c e we have a l t e r e d  and have l e f t  Similarly,  of  process.  income and s u b s t i t u t i o n  present  change;  p r i c e ; and  Hence t h e l o n g t e r m a d j u s t m e n t t o Q2 from real  and i s l e s s  t o 0;  Q1 i s t h e o r i g i n a l c o n s u m p t i o n  Rearranging  elasticity  likely f o r an  the to  average be  price  negligible.  industrial  consumer,  change.  the  only the marginal  unchanged, Therefore the  In  the  income  i t i s ignored.  price  effect  is  107  assumed  to  effects  are  elasticity  take  place along  not  considered.  is  used  estimate  the  marginal  price  the use  quantity  described marginal marginal bulk  long  run  P1,  P2,  year  and  several  rates of  output  than  point,  us t o more a c c u r a t e l y a  relatively  large  c a r e must be e x e r c i s e d i n  f o r very  non-linearity  difficult  own  of  large price  t h e demand  implications  4.  changes  curve.  17,15  and 24,  10  and  and  22  choice as  take  customers,  somewhat  KWH  (13)  i n the o l d  and  Q2  new  general  used,  a  given  f o r the c u r r e n t  implemented  An  and  elasticity  of  The  new  i n 1981, the  and  ultimate  (Wilson,  coefficients  outside study own from  1974).  residential  -1.0  to  i s as  commissioned  price e l a s t i c i t i e s  u s i n g monthly  higher  the  assigned  i s then  the r e v i s e d  model  place.  long run  customers  1964-1972 p e r i o d  per  sees o n e - f i f t h  appropriate  estimated  t o read  Each c l a s s i s a l s o  be f u l l y  1981  i t i s important.  residential  residential  of  structure  hence f o r e a c h c u s t o m e r c l a s s .  and  adjustment  rate  mills for residential,  Equation  i s assumed t o 1977  a r e used  mills  e, t o d e t e r m i n e  that s i x years  of  must be i n t r o d u c e d t o t h e  Coefficients  price elasticity.  Q1,  Hydro  suggest  the  customers r e s p e c t i v e l y .  consumption  the  from  estimates  features  r a t e s o f 26,  structure  The  new  i n Chapter  each y e a r between  for  enables  change..Nevertheless,  o r d e r t o examine  reform,  B.C.  rather  thus  Modelling In  rate  it  i s o g u a n t , and  arc,  adjustment  because of the i n e v i t a b l e  and  The  because  of the e l a s t i c i t y  6.2.2  a given  -2.3  by  of  -0.35  for  non-  data f o r 5 r e g i o n s d u r i n g Other  studies  elasticities  and  tend  to  somewhat  108  lower  non-residential figures.  various  estimates  of l o n g  Table  r u n own  6 presents  the  price elasticities  results  of  by c u s t o m e r  TABLE 6  A SURVEY O f ESTIMATED LONG RUN E L A S T I C I T I E S OF ELECTRICITY  OWN PRICE DEMAND  Residential Anderson(1973) F e d e r a l E n e r g y A d m i n i s t r a t i o n (1976) F i s h e r and K a y s e n ( 1 9 6 2 ) Griffin{1974) Halvorsen(1973) H o u t h a k k e r and T a y l o r ( 1 9 7 0 ) H o u t h a k k e r , V e r l e g e r and Sheehan(1973) Mount, Chapman and T y r r e l l (1973) T a y l o r , B l a t t e n b e r g e r and V e r l e g e r { 1 9 7 6 ) Uri(1975) Wilson{1971) Wilson{1974) Wilson<1974a)  -1.12 -1.46 0.0 -0.52 -0.97 -1.89 -1.02 -1.20 -0.78 -1.66 -2.00 - 0 . 18 -0.35 -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 ) Griffin(1974J Halvorsen(1973) Mount, Chapman and T y r r e l l ( 1 9 7 3 ) Uri(1975) Wilson{1974)  -0.38 -0.51 -0.91 -1.36 -0.85 -1.0 -2.3  Industrial A n d e r s o n (1973) B a x t e r and R e e s ( 1 9 6 8 ) F e d e r a l E n e r g y A d m i n i s t r a t i o n (1976) F i s h e r and K a y s e n ( 1 9 6 2) Griffin(1974) Halvorsen(1973) Mount, Chapman and T y r r e l l ( 1 9 7 3 ) Uri(1975) Wilson{1971) Wilson{1974)  -1.94 -1.50 - 0 . 15 -1.25 -0.51 -1.24 -1.82 -0.35 -1.33 -1.2 -2.3  109  class.7s of  .4,  As  a base c a s e ,  .6 and  .8  respectively. low  end  and  The  .7,  and  i t  coefficient curve  Sensitivity .8 and  this be  which may  energy  Given likely the  analysis at the  the  100  .*», and  will  marginal  percent  used  increase  to r e f l e c t  become i m p o r t a n t from  10  for  t o 22  stock  of  combined  rate  of  10  o f t h e i n c r e a s e . We  classes  .6  a l s o be  price  at  run.  for  o f 50  the  both  percent,  the bulk customers.  suggests  that  a  The  reduced  the n o n - l i n e a r i t y  i n the  for  this  an  increase.  mills,  we  the  fact  electricity  affected  estimates  industrial  u s i n g .2,  h i g h end  real  latter  t o be p r i m a r i l y  the impact  g e n e r a l and  value  large disguise  r a t e i s recommended t o i n c r e a s e from  that the  initial  1.2  absolute  g e n e r a l customers i s i n the o r d e r  However, i n g o i n g the  in  exceeds  magnitude o f  s h a l l use  for residential,  increase  residential whereas  7 6  we  by  consuming  the energy  mills  will  to  19  that  mills.  eguipment  charge,  tend  t h e r e f o r e use  3 to  demand  the  use  is of  underestimate  the f u l l  elasticity  These results are presented t o g i v e an i n d i c a t i o n o f t h e range of elasticity estimates that have been observed. Considerable variation 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 analysis, particularly as regards the price of electricity, makes some of these s t u d i e s more r e l e v a n t t h a n others f o r the purposes of t h i s paper. The e s t i m a t e s f o r b u l k c u s t o m e r s may i n f a c t be t o o low g i v e n their tendency to ignore the large potential for 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 industrial users in B.C. Were the economic incentives present, greater use o f t h e 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 o f wood waste would be made., Such selfgeneration, with i t s large energy component (relative to c a p a c i t y ) and i t s t e n d e n c y t o peak i n t h e w i n t e r months, would complement B.C. Hydro's s y s t e m . The c u r r e n t low m a r g i n a l r a t e f o r b u l k c u s t o m e r s , w i t h 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, p r o v i d e s l i t t l e e n c o u r a g e m e n t f o r t h e d i s p l a c e m e n t o f Hydro's power by that which i s s e l f - g e n e r a t e d . M o r e o v e r , t h e p r i c e w h i c h B.C. Hydro i s o f f e r i n g f o r s u r p l u s e n e r g y , raised recently t o between 5 and 6 m i l l s , i s f a r below t h e A u t h o r i t y ' s m a r g i n a l e n e r g y c o s t s and f u r t h e r d i s c o u r a g e s the installation of the economically appropriate guantity of s e l f - g e n e r a t i n g capability. 7 5  7 6  110  estimate effort  on  the  to o f f s e t  A related impact On  t h e two  load factor  to  reduce  the  peak  charge  that  coincidence  with  the  system's l o a d f a c t o r . out  of  factor  these  two  assumption  The  new  different  figures  case  marginal  will  customer's  load f a c t o r .  However, a  related  to  peak would  analysis  we  f o r c e s and  t o improve  of the  cancelling  the system  load  7 7  undertaken  with  degree  assume t h e  maintain  expansion  can  the  tend  plan  be a  also  c o s t s can  o f t h e same v a r i e t y  us  the  customers  percent.  was  make a b o u t  f o r the bulk  costs  provide  we  of  be  provides a determined.  demand  i n the l a s t obtained.  shocks  chapter,  These  revised  better understanding  of the e s t i m a t e s  to the b a s e c a s e  new  of  the  that  is  examined.  6.2.3  Results Table  reform  7  highlights  under the  results structure last  biases.  which m a r g i n a l  as  i n an  peak c h a r g e  and  from  mills)  structure.  was  opposing  degree o f s e n s i t i v i t y being  t o 22  rate  this  the impact  base  estimates of  In  o f 63.5  base c a s e  this  {10  of the reformed  system's  operating  By c a l c u l a t i n g on  change  conflicting  hand, t h e r e d u c e d  tend  customer  price  c o n s i d e r a t i o n i s the assumption  on t h e s y s t e m  t h e one  will  modified  in  the  and  chapter.  the  implications  assumptions o u t l i n e d first  column  assume  are t h e r e f o r e i d e n t i c a l The  next  i n the no  of  rate structure  last change  t o those  t h r e e show t h e e f f e c t s  section.  The  i n the  rate  presented  in  of reformed  the rate  The e x t e n t t o w h i c h a l t e r i n g t h e r e l a t i v e and a b s o l u t e e n e r g y and peak p r i c e s a f f e c t s t h e i n d i v i d u a l ' s and t h e system's load f a c t o r i s an i m p o r t a n t , y e t r e l a t i v e l y u n s t u d i e d , a r e a . 7  7  TABLE 7 IMPLICATIONS OF RATE STRUCTURE REFORM  NO RATE STRUCTURE REFORM  Growth R a t e In Demand (%) (1976 - 1990) Average Accounting Cost (1976 M i l l s p e r KWH) (1976 - 1990)  RATE STRUCTURE REFORM WITH DIFFERENT PRICE ELASTICITY ASSUMPTIONS Low  Base C a s e  High  9„0  7.8  7.0  5 7  18.1  17.1  16.5  16.1  13.4  11.2  10.2  G r o s s 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 $)  112  structures  under  assumptions.  As  elasticities, 1990  years  would  the lower  period.  between  increasingly  In  large  be  t h e growth r a t e  fact,  the  the  declines  elasticities  s t r u c t u r e h a s been  fully  respond  to  elasticity  greater  i n demand i n  t h e major r e a d j u s t m e n t  high  primarily  price  expected,  1977 and 1981, w i t h s l i g h t under  own  implemented,  1976-  i n demand  Once  demand  occurs in  two  t h e new  is  the v a r i o u s f a c t o r s i m p l i c i t  F o r c e p r o j e c t i o n s and a v e r a g e s  the  occurring  case.  these  rate  assumed  to  i n the Task  8.5 p e r c e n t i n a l l c a s e s  in  the  1982- 1990 p e r i o d . The  reduced  growth  new  generation  expensive  rates  d e f e r t h e need  sources,  7 8  average  a c c o u n t i n g c o s t s and i n v e s t m e n t .  derived  by t a k i n g  and  1990, a d d i n g  converting of energy this  c o s t s ranges elasticities) elasticities  debt  1976 d o l l a r s ,  reducing  both  two o f T a b l e year  6  between  any e x p o r t  last  The r e d u c t i o n i n r e a l from  5.4  with  a  unit  t o 11.0  over  net accounting percent  (high  v a l u e o f 8.8 p e r c e n t under t h e base  case  assumption. row o f t h e t a b l e  outstanding  indicates  the  anticipated  ( a t t r i b u t a b l e t o the e l e c t r i c  Hydro i n 1990 i n b i l l i o n s good p r o x y  1976  d i v i d i n g by t h e g u a n t i t y  average  (low e l a s t i c i t i e s )  is  revenue,  g e n e r a t e d b y B.C. H y d r o and a v e r a g i n g t h e r e s u l t s  period.  The  How  any net i n c o m e , s u b t r a c t i n g into  more  thereby  a l l a c c o u n t i n g c o s t s i n each  the t o t a l  to develop  for total  of h i s t o r i c  investment  dollars.  during this  service)  gross o f B.C.  T h i s s e r v e s as  period  since  a  most o f  T h e s e new s o u r c e s a r e more e x p e n s i v e t h a n t h e o l d ones both in real terms and b e c a u s e o f t h e d i s t o r t i o n s o f t h e a c c o u n t i n g system ( p a r t i c u l a r l y d u r i n g p e r i o d s o f i n f l a t i o n ) discussed i n the l a s t c h a p t e r . 7 8  11.3  the  Authority's  capital  d e b t f i n a n c i n q . The percent  using  and  percent  38.1 The  the  growth r a t e  one  percent  high  reductions after  from the  reveals  over  i n the  of  first  the  next  last  to  load  were  T a b l e 5.  The  economic  500  million  compiled  7.0  percent  compared  period.  with The  component  growth r a t e the  9.0  energy fell  from  percent  with the  B.C.  Indeed, i t i s  KWH  of  apparent.  similar  in  both  .4,  .6  7 9  m i l l s per  earlier  KWH  .8.  The  presented  KWH  using  r e s u l t of the  while at  forecast  capacity  growth o v e r  3.2  the  those  slightly  directions  and  m i l l s per  rose  2.4  resulting  which  22.1  of  only  a l s o undertaken i n  with the  rate  growth  that  component to  from  demand  a v e r a g e combined m a r g i n a l e n e r g y and f o u n d t o be  on  to  same manner as  l a r g e c u s t o m e r s was  first  results  f a c t o r s were i m p o s e d on  i n the  returns The  savings  costs  was  for  mills  cost  base c a s e demand e l a s t i c i t i e s  results  This  become p a r t i c u l a r l y  chapter  and  different  for  20.4  a l a r g e r impact  associated  period.  33.1  assumptions.  attractiveness of  opportunities  10  the  costs  half of t h i s  demand s h o c k s of from with  percent.  by  extremes of  decreasing  has  met  is  1976-1990 p e r i o d .  one  fixed  a n a l y s i s of marginal the  the  t o he  level  with  of  growth r a t e  which r e d u c e s t h e  in  debt  existence  d i f f e r e n t growth r a t e s  performed  using  the  t h a n does the  that  1990  continue  alternative elasticity  reductions  i n the  1982  An  under t h e  proportion  Hydro s y s t e m  i n the  base case e l a s t i c i t i e s ,  reduction  average c o s t s the  reduction  table also  from  requirements w i l l  the  in  cost the 22.6  1976-1990 the  system  peak load  A s y s t e m w i t h a g r e a t e r t h e r m a l component would d e r i v e more i m m e d i a t e b e n e f i t s f r o m 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 t h e B.C. Hydro c a s e r e - e m p h a s i z e s t h e 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 r e f o r m w i t h the a p p r o v a l o f major new projects. 7 9  114  factor.  In l i g h t  estimates,  no  of the apparent s t a b i l i t y redesign  of rate  costs.  cost  s t r u c t u r e s and r e - e s t i m a t i o n  demand was deemed n e c e s s a r y t o r e f l e c t m a r g i n a l economic  i n the marginal  t h e new, s l i g h t l y  of  lower,  115  I-.  The  primary  SDH MARY AND CONCLUSIONS -  purpose o f t h i s  a p p l y a m a r g i n a l economic the  costing  predominantly h y d r o - e l e c t r i c  approach  adopted  electricity (savings)  fundamentally  methodology system  i s o n e whereby e a c h  is  which  p a p e r h a s been  allocated  those  accounting costs  the  o f B.C. Hydro.  incremental will  associated  with  The  approaches  which  while  costs  f o r each customer  are  keeping  marginal  economic  component than are  does  average  price  class.  of  demand  from  by  with  which t h e are  split  arbitrary  marginal  For the l a r g e r  t h o s e now  users  leads  a  rate  economic  (both w i t h i n  to  in effect.  attaches f a r greater in  adopting  e g u a l to average a c c o u n t i n g  substantially In p a r t i c u l a r ,  weight t o t h e  the energy-critical  reduction  in  the  growth  i n d u c e d by t h e new about  rate  marginal  each  energy  B.C. Hydro of t h i s  o f demand. The e n s u i n g d e c l i n e  expensive  projects  are  deferred  in  is  average  unit  i s  class's  system  analysis  demand  for  quantified own  price  i n c o s t s a s new,  also  calculated.  were p r e s e n t e d i n T a b l e 7 and i n d i c a t e d  9 percent i n the r e a l  the  prices  customer  elasticity  over  differs  i n T a b l e 8.  assumptions  results  plant  t h e a c c o u n t i n g a p p r o a c h . The r e s u l t s  electricity using  rates  analysis  summarized The  under  t o somewhat  reconciled  each c l a s s and w i t h i n t h e s y s t e m ) , t h i s  the  basic  costs  cause. This  in-service  equates marginal price  cost  higher  for  criteria. two  structure  The  economic  t e c h n i g u e now employed  between t h e components o f demand a c c o r d i n g accounting  appropriate  component o f t h e demand f o r  a c h a n g e i n i t s demand from  t o d e v e l o p and  a  more These  reduction  of  annual a c c o u n t i n g c o s t s  116  and  over  the  40  p e r c e n t i n the g r o s s debt  median  structure The enable  elasticity  estimates  o u t s t a n d i n g i n 1990  over  purpose  individual  of the  reguired  attractive  marginal to  make  will  subsidization  of  lead the  s o c i e t y ' s l o n g term The  consumer  and  structures  an  utilities.  to  being  priced  within  is  consumption  There  economic  recent  well  price of e l e c t r i c i t y  energy  situation  sought  blocks.  This  statement  by  energy  rate  charge,  in this  strong p o l i t i c a l strucutes  charge  in  and  technology  cannot  Such be  in  by  their  rate  particularly  acute  where r e c o v e r y o f  through  high  t o the  charges latter  i n the r i g h t  the on  blocks  costs. these  concerns  rate structures  rate structure  and  direction. l e t  a  with the balance being c o l l e c t e d  by  Indeed,  the  would  (Bonner, have  i s at odds with  paper.  The  t h e C h a i r m a n of t h e a u t h o r i t y  end  any  be  leads  are c l e a r l y  very  large front  society.  reform  moves t o w a r d s f l a t t e r  that the " i d e a l "  outlined  can  utilities  often  charges  its  being recognized  Some a r e moving t o  1977), i n d i c a t i n g  a flat  i s now  below c u r r e n t m a r g i n a l e c o n o m i c  Hydro. The  to  achieve  inefficiencies.  i s some e v i d e n c e o f a r e c o g n i t i o n o f  B.C.  increased a  costs  to  is  interests.  a c c o r d i n g l y . The  fixed  to  electricity-conserving  with predentinatly h y d r o - e l e c t r i c  initial  rate  p r i c e below i t s r e a l economic v a l u e  marginal best  firm  costly  relevance of these concerns  many e l e c t r i c  large  w i t h no  o f moving t o w a r d s m a r g i n a l c o s t p r i c i n g  o b j e c t i v e s i n a manner w h i c h i s l e a s t  that  case  reform.  each  setting  the  using  economic  t h e r e does n o t now  principles appear  o r s e n i o r management committment accordance  with  to  to  be  reform  the o b j e c t i v e o f economic  TABLE 8 MARGINAL AND AVERAGE PRICES OF ELECTRICITY (1977^/KWH)  CUSTOMER CLASS  MARGINAL EXISTING (as o f May 1977)  AVERAGE  PROPOSED  EXISTING/PROPOSED  3  Peak  „R e .s i.d e*n t.i a,l  General  Bulk  Energy  Peak  .8 2.0 .6  Varies Widely .6 (approx.)  .4  .3  Energy  v^^,2.0 2.8  -^^^ 2.6  Peak and E n e r g y  3.1  2.0.  2.0  2.9 1.1  118  efficiency.  119  BIBLIOGRAPHY A c h a r y a , Shankar N. (1972), "Public Enterprise P r i c i n g ana Social Benefit-Cost Analysis" i n Niskanen, W.A. e t a l ( e d . ) , B e n e f i t - C o s t and P o l i c y A n a l y s i s , A l d i n e Publishing Company, C h i c a g o . Anderson, K.P. (1971), "Toward Econometric Estimation of Industrial Demand: An Experimental Application to the P r i m a r y M e t a l s I n d u s t r y " , The Rand C o r p o r a t i o n (R-719-NSF), December, 1971. Anderson, K.P. Analysis", 1973.  ( 1 9 7 3 ) , " R e s i d e n t i a l E n e r g y Use: An E c o n o m e t r i c The Rand Corporation (R-1297-NSF), October,  Barnett, George (1977), Committee, B.C. Hydro,  Submission Vancouver.  to  Revelstoke  Appeal  B a x t e r , R.E. and R.Rees (1968), "Analysis of the I n d u s t r i a l Demand f o r E l e c t r i c i t y " , Economic J o u r n a l , V o l . 78, J u n e , 1968. Berlin, Edward, C.J. C i c c h e t t i and H.J. Gillen (1974), Perspectives on Power: A Study o f t h e •• R e g u l a t i o n and Pricing of E l e c t r i c Power, Ballinger Publishing Co., Cambridge, M a s s a c h u s e t t s . B e r n d t , E r n s t R. ( 1 9 7 6 ) , " C a n a d i a n Demand f o r E n e r g y ; A s u r v e y " , Department o f Economics, U n i v e r s i t y o f B r i t i s h Columbia, O c t o b e r , 1976. B o n b r i g h t , James C. ( 1 9 6 1 ) , P r i n c i p l e s o f P u b l i c U t i l i t y C o l u m b i a U n i v e r s i t y P r e s s , New Y o r k . Bonner, Robert H. (1977), "Letter of P r o v i n c e , V a n c o u v e r , A p r i l 7, 1977.  the  day",  Rates.  Vancouver  B r i t i s h Columbia Energy Commission (1975), "A Response t o D a v i d Cass-Begg*s Article 'The F u t u r e o f E l e c t r i c Power i n B r i t i s h Columbia*" , a paper presented a t the Canadian N a t i o n a l E n e r g y Forum, O c t o b e r , 1975. British Columbia Energy Commission (1976), B r i t i s h E n e r g y Outlook:. 1976-1991, Volumes 1 and 2, A p r i l , 1976. British C o l u m b i a Hydro and Power A u t h o r i t y R e p o r t s , V a n c o u v e r , 1963-1976.  Columbiajs Vancouver,  (1973-1976a),  Annual  British Columbia Hydro and Power Authority (1974b), The A v a i l a b i l i t y o f Hog F u e l f o r G e n e r a t i o n o f T h e r m a l Power i n B r i t i s h C o l u m b i a . V a n c o u v e r . J u n e , 1974. British  Columbia  Hydro  and Power A u t h o r i t y  (1975b), A l t e r n a t i v e s  120  1975 t o 1990: R e p o r t o f t h e T a s k F o r c e on F u t u r e G e n e r a t i o n and T r a n s m i s s i o n R e g u i r e m e n t s , V a n c o u v e r , flay, 1975. British C o l u m b i a Hydro and Power A u t h o r i t y ( 1 9 7 5 c ) , " P r o s p e c t u s f o r I s s u a n c e o f $150,000,000 9 5/8% Bonds", V a n c o u v e r , May, 1975. B r i t i s h C o l u m b i a Hydro and Power A u t h o r i t y (1975d), F i n a n c i a l I n f o r m a t i o n f o r Year Ended March Vancouver. British C o l u m b i a Hydro and Power A u t h o r i t y f o r Issuance of $175,000,000 8 5/8% November, 1976.  "Comparative 31, 1975",  (1976b), " P r o s p e c t u s Bonds", Vancouver,  British Columbia Hydro and Power A u t h o r i t y 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 , Volumes J u n e , 1976.  (1976c), Revelstoke 1 and 2, V a n c o u v e r ,  B r i t i s h C o l u m b i a Hydro and Power A u t h o r i t y (1976d), Revelstoke Project: E n v i r o n m e n t a l Impact S t a t e m e n t , Volumes 1 and 2, V a n c o u v e r , May, 1976. , B r i t i s h C o l u m b i a Hydro a n d Power Authority Hydro S t o r j j , V a n c o u v e r , J u n e , 1976. B r i t i s h Columbia Victoria.  Legislature  (1976e),  The  ( 1 9 6 0 ) , Power A c t , Queen's  B r i t i s h C o l u m b i a L e g i s l a t u r e (196 4 a ) , B r i t i s h C o l u m b i a Power A u t h o r i t y A c t , Queen's P r i n t e r , V i c t o r i a . British Columbia Legislature Queen's P r i n t e r , V i c t o r i a . C a l l e n J . , G.F. Mathewson, and and Costs of Rate of Economic Review, 66, J u n e  (1964b),  Power  C a m p b e l l , H a r r y F. ( 1 9 7 5 ) , "A B e n e f i t - C o s t R u l e P u b l i c P r o j e c t s i n Canada", C a n a d i a n P u b l i c  Printer, Hydro  Measures  H. M o h r i n g (1976) "The Return R e g u l a t i o n " , The 1976, pp. 290-290.  fi^CL.  and Jet.,,  Benefits American  for Evaluating P o l i c y , 1, 2.  Canada, N a t i o n a l Energy Board (1975), Report t o t h e Governor i n C o u n c i l I n t h e M a t t e r o f t h e A p p l i c a t i o n under t h e N a t i o n a l Energy Board Act of British Columbia Hydro and Power A u t h o r i t y , O t t a w a , J u n e , 1975. Canada, Office of Energy Conservation ( 1 9 7 6 ) , Department o f Energy Mines and Resources, "Submission t o the Royal Commission on E l e c t r i c Power P l a n n i n g " , December 8, 1976. Caywood, Russell E. (1956), McGraw-Hill, Toronto. Christensen, i n U.S.  Electric  Utility  Rate  Economics,  L a u r i t s and w.H. G r e e n e ( 1 9 7 6 ) , "Economies o f S c a l e E l e c t r i c Power G e n e r a t i o n " , J o u r n a l of Political  121  Economy,  V o l . 84, No. 4, P a r t  1, A u g u s t ,  1976.  C i c c h e t t i , C h a r l e s J . , W.J. G i l l e n , and P. Smolensky ( 1 9 7 6 ) , The Marginal Cost and Pricing of Electricity; An Applied Approach, a P r e l i m i n a r y Report to the National Science Foundation in cooperation with the Planning and C o n s e r v a t i o n F o u n d a t i o n , Sacramento, C a l i f o r n i a . C i c c h e t t i , C h a r l e s and J . J u r e w i t z (1975), S t u d i e s i n Electric Utility Regulation, a Ford Foundation Report, B a l l i n g e r P u b l i s h i n g , Cambridge, Massachusetts. Crew, M. (1958), " E l e c t r i c i t y T a r i f f s " , i n T u r v e y , R a l p h (ed.), P u b l i c E n t e r p r i s e . P e n g u i n Books, M i d d l e s e x , E n g l a n d . Electric Power Research Institute (1976a), A Preliminary F o r e c a s t o f Energy C o n s u m p t i o n T h r o u g h 1985, S p e c i a l R e p o r t 37, P a l o fllto, C a l i f o r n i a , M a r c h , 1976. E l e c t r i c Power R e s e a r c h I n s t i t u t e (1976b), Interim Report of Electric Utility Rate Design Study Task Force No 1: Analysis of Various Pricing Approaches. Palo Alto, C a l i f o r n i a , J u l y 15, 1976. Federal Energy Administration (1976), 1976 National O u t l o o k , F e d e r a l Energy A d m i n i s t r a t i o n , W a s h i n g t o n ,  Energy D.C.  F i s h e r , F.M. and C. Kaysen ( 1 9 6 2 ) , A Study i n E c o n o m e t r i c s ; The Demand f o r E l e c t r i c i t y i n t h e U n i t e d S t a t e s , North H o l l a n d P u b l i s h i n g Co., Amsterdam. Foster Associates, Missouri Public Service Commission, and University o f M i s s o u r i - C o l u m b i a (1976), P r o c e e d i n g s o f t h e -122JJ Symposium on Rate D e s i g n P r o b l e m s of Regulated I n d u g t r i e s , Kansas C i t y , M i s s o u r i , F e b . 1976. Puss,  Melvyn A. (1977), "The demand f o r energy i n Canadian m a n u f a c t u r i n g : An example o f t h e e s t i m a t i o n o f p r o d u c t i o n s t r u c t u r e s w i t h many i n p u t s " , J o u r n a l of E c o n o m e t r i c s , V o l . 5, No. 1, J a n u a r y , 1977.  Gaffney, Mason (1974), " T a x a t i o n t o Make J o b s by A c t i v a t i n g Wealth", prepared f o r 8th Annual Conference of the Committee on T a x a t i o n , R e s o u r c e s , and Economic D e v e l o p m e n t , M a d i s o n , W i s c o n s i n , A u g u s t , 1974. Gaffney, Mason (1976), "Capital Reguirements for Growth", a paper contributed t o the Joint Committee Study Series, Economic Growth from P r o s p e c t s , P r o b l e m s and P a t t e r n s , A u g u s t , 1976. G a r f i e l d , P a u l and W. L o v e j o y ( 1 9 6 4 ) , P u b l i c U t i l i t y P r e n t i c e - H a l l , Englewood C l i f f s , New J e r s e y . Griffin, J.M. Electricity  (1974), "The Effects of Higher C o n s u m p t i o n " , B e l l J o u r n a l , Autumn.  Economic Economic 197 5-85:  Economics, Prices 1974.  on  122  H a l v o r s e n , R o b e r t ( 1 9 7 3 ) , "Demand for Electric Power i n the United States", D i s c u s s i o n paper No. 73-13, I n s t u t i t e f o r Economic R e s e a r c h U n i v e r s i t y o f W a s h i n g t o n , December, 1973. H e l l i w e l l , John F. , and John L e s t e r ( 1 9 7 5 ) , "A New Approach to Price Setting f o r R e g u l a t e d P i p e l i n e s , " The L o g i s t i c s and T r a n s p o r t a t i o n R e v i e w , V o l 11, No. 4. H e l l i w e l l , John F. e t a l ( 1 9 7 6 ) , "An I n t e g r a t e d Model f o r E n e r g y P o l i c y A n a l y s i s " , Resources Paper No. 7, Oniversity of B r i t i s h C o l u m b i a , December, 1976. Helliwell, John F. (1977), "The Economic Performance of Regulated I n d u s t r i e s i n Canada: Some Problems f o r the 1980*s", a p a p e r p r e p a r e d f o r t h e C o n f e r e n c e on R e g u l a t i o n i n Canada: P r o c e s s and P e r f o r m a n c e . C h a t e a u M o n t e b e l l o , 3-5 March, 1977. H e n d r i c k s , W a l l a c e , Roger K o e n k e r , and R o b e r t Podlasek (1977), "Consumption patterns for electricity", Journal of E c o n o m e t r i c s , V o l . 5. No. 2, M a r c h , 1977. H o u t h a k k e r , H.S. and L.D. T a y l o r (1973), Consumer D e m a n d i n t h e United States. 2nd e d i t i o n . Harvard University Press, Cambridge, M a s s a c h u s e t t s . Houthakker, H.S., P.K. Verleger and D.P. Sheehan (1973), "Dynamic Demand Analyses f o r Gasoline and Residential Electricity", Data Resources Inc., Lexington, Massachusetts. Jenkins, Glenn P. (1973), "The Measurement o f R a t e s o f R e t u r n and T a x a t i o n f r o m P r i v a t e C a p i t a l i n C a n a d a " , i n N i s k a n e u , William A. ( e d . ) , B e n e f i t - C o s t and P o l i c y A n a l y s i s , A l d i n e P u b l i s h i n g Co., C h i c a g o . Joskow, P a u l . L . (1976), " C o n t r i b u t i o n s t o t h e T h e o r y o f M a r g i n a l C o s t P r i c i n g " , The B e l l J o u r n a l o f E c o n o m i c s , V o l . 7, No. 1, S p r i n g , 1976. Kahn,  A l f r e d E. (1971), The E c o n o m i c s o f R e g u l a t i o n : P r i n c i p l e s and I n s t i t u t i o n s , , J o h n W i l e y and Sons, I n c . , T o r o n t o , V o l . 2.  Kaiser Aluminum and C h e m i c a l Corporation (1976), At I s s u e : Electricity - Pricing a Critical Resource i n an EnergyS h o r t E n v i r o n m e n t , O a k l a n d . C a l i f o r n i a , O c t o b e r , 1976. L e w i s , W. A.  (1949), Overhead  Costs,  London.  Lipsey, Richard G., G.R. Sparks and P.O. Steiner E c o n o m i c s , H a r p e r and How, New York, New York. M. and M. Systems ( 1 9 7 5 ) , E n e r g y and Two Edmonton. x  Regulation Study:  (1973),  R e p o r t s - One  123  Marglin, Stephen Investment", Kay, 1963. flay,  A. (1963), "The O p p o r t u n i t y C o s t s o f P u b l i c Q u a r t e r l y J o u r n a l o f E c o n o m i c s . L X X V I I , No. 2,  G e r r y ( 1 9 7 6 ) , " S y n c r u d e and Evaluation," M. A. , T h e s i s , Summer, 1976.  the Oil University  Sands: An of British  Economic Columbia,  Mount, T.D., L.D. Chapman and T . J . T y r r e l l ( 1 9 7 3 ) , "Electricity Demand i n t h e U n i t e d S t a t e s : An E c o n o m e t r i c A n a l y s i s " , Oak Ridge National Laboratory (ORNL-NSF-49), Oak Ridge, Tennessee, June, 1973. McRae, R o b e r t N. ( 1 9 7 6 ) , "A Q u a n t i t a t i v e A n a l y s i s o f Some P o l i c y Alternatives Affecting C a n a d i a n N a t u r a l Gas and C r u d e O i l Demand and Supply", Preliminary Version, Ph.D. Thesis, U n i v e r s i t y o f B r i t i s h Columbia, October, 1976. National E c o n o m i c R e s e a r c h A s s o c i a t e s (1975), " T e s t i m o n y t h e N o r t h C a r o l i n a U t i l i t i e s C o m m i s s i o n " , New York, November, 1975. Nelson, James R. Prentice-Hall, Newton, T i m o t h y , J . Committee, B.C.  (196 4 ) , Marginal Cost P r i c i n g I n c . , Englewood C l i f f s , N . J . (1977), Submission Hydro, V a n c o u v e r .  to  Northwest Public Power Association Symposium: P r o c e e d i n g s . V a n c o u v e r ,  in Practice,  Revelstoke  Northwest Public Power Association (1974), Symposium, S e a t t l e , W a s h i n g t o n , J u l y , 1974.  Before N.Y.,  Appeal  Retail  Rates  (1975), Retail Washington, J u l y ,  Rates 1975.  Northwest Public Power Association (1976), Symposium: P r o c e e d i n g s . V i c t o r i a , B.C., J u l y ,  NWPPA 1976.  Rates  O n t a r i o Hydro ( 1 9 7 6 a ) , "Impact of Rate Structures and Rate Levels: Memorandum to the Royal C o m m i s s i o n on E l e c t r i c Power P l a n n i n g with respect to the Public Information H e a r i n g s " , T o r o n t o , June, 1976. Ontario Hydro (1976b), "Proposed Toronto, July, 1976.  Bulk  Power R a t e s  O n t a r i o Hydro ( 1 9 7 6 c ) , E l e c t r i c i t y C o s t i n g and Volumes 1 t o 10, T o r o n t o , O c t o b e r , 1976.  f o r 1977",  Pricing  Ontario, Ministries of Energy and E n v i r o n m e n t ( 1 9 7 6 ) , Wood Wastes Energy S t u d y : A P r e l i m i n a r y F e a s i b i l i t y December, 1976.  Study. Hearst S^tudv^  Pachauri, R.K. ( 1 9 7 5 ) , The Dynamics o f E l e c t r i c a l E n e r g y S u p p l y and Demand: An Economic A n a l y s i s , P r a e g e r Publishers, New York.  124  Panzer, J.C. (1976), p r i c i n g " , The B e l l Autumn, 1976.  "A neoclassical approach t o peak l o a d J o u r n a l o f Economics,, V o l . 7, No. 2,  Phillips, C h a r l e s P. J r . ( 1 9 6 5 ) , The E c o n o m i c s o f R e g u l a t i o n ; Theory and Practice i n the Transportation and Public Utility Industries, Bichard D. Irwin, Inc., Homewood, Illinois. P u b l i c S e r v i c e C o m m i s s i o n of W i s c o n s i n ( 1 9 7 4 ) , F i n d i n g s o f Fact and O r d e r ; A p p l i c a t i o n o f Madison Gas and E l e c t r i c Company f o r Authority to Increase Its Electric and Gas Rates, Madison, Wisconsin. Public  Utilities  Fortnightly,  I s s u e s from  1973  to  1977.  Rosenberg, Lawrence C. (1967), "Natural gas Pipeline Rate R e g u l a t i o n : M a r g i n a l C o s t P r i c i n g and t h e Zone Allocation Problem", Journal of Political Economy, V o l . 75, No. 2, A p r i l , 1967. ~ S u g g l e s , Nancy ( 1 9 4 9 ) , "The W e l f a r e B a s i s o f t h e Marginal Cost Pricing Principle: Recent Developments i n the Theory o f M a r g i n a l C o s t P r i c i n g " , Review o f Economic Studies. XVII ( 1 - 2 ) , Nos. 42-43, 1949-1950. Scherer, C.R. (1976), " E s t i m a t i n g Peak and O f f - p e a k M a r g i n a l C o s t s f o r an E l e c t r i c a l Power System: an E x - A n t e Approach", The B e l l J o u r n a l o f E c o n o m i c s . V o l . 7, No. 2, Autumn, 1976. Schramm, G u n t e r ( 1 9 6 9 ) , " R e l a t i v e P r i c e Changes and t h e B e n e f i t s and C o s t s o f A l t e r n a t i v e Power Projects", The Annals of R e g i o n a l S c i e n c e . December, 1969. S e l e c t Committee o f t h e O n t a r i o L e g i s l a t u r e ( 1 9 7 6 ) , A - New Public P o l i c y D i r e c t i o n f o r O n t a r i o Hydro: F i n a l Report. Toronto. Shaffer, Marvin (1976), "The Economic C o s t o f a H y p o t h e t i c a l E l e c t r i c Power Shortage: Prepared for British Columbia Hydro and Power A u t h o r i t y " , mimeo, A u g u s t , 1976. Smith, Arthur J.R. ( 1 9 7 6 ) , " F u t u r e I n d u s t r i a l Uses o f E n e r g y : S e l e c t e d Aspects o f A l l o c a t i o n " , notes f o r remarks to the Symposium on Ontario's E l e c t r i c a l Future. November 19, 1976. Solow, R.M., and F.Y. Wan (1976), "Extraction Costs in the Theory of E x h a u s t i b l e Resources", The Bell Journal of EconomicSj, V o l . 7, No. 2, Autumn, 1976. S t a t e o f New Y o r k , P u b l i c S e r v i c e C o m m i s s i o n ( 1 9 7 6 ) , O p i n i o n and Order R e q u i r i n g the E s t a b l i s h m e n t of Time-of-Day Rates for Large Commercial and Industrial Customers: Long I s l a n d L i g h t i n g Company,, December 16, 1976. Statistics  Canada  (1976), F i x e d C a p i t a l  Flows  and  Stocks,  1972-  125  76  x  13-211, O t t a w a .  Steiner, Peter 0. (1965), "The Role of A l t e r n a t i v e Cost i n Project Design and Selection", Quarterly Journal of E c o n c m i c s ^ V o l . LXXIX , No. 3, A u g u s t , 1965. T a y l o r , L.D. ( 1 9 7 5 ) , "The demand f o r e l e c t r i c i t y : a s u r v e y " . B e l l J o u r n a l o f E c o n o m i c s , V o l . 6, No. 1, S p r i n g , 1975.  The  Taylor, Lester D. ( 1 9 7 6 ) , "The Demand f o r E n e r g y : A s u r v e y o f P r i c e and Income E l a s t i c i t i e s " , a r e p o r t p r e p a r e d for the National Academy of Science Committee on Nuclear and A l t e r n a t i v e E n e r g y Systems. 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. Verleger, J r . (1976), The Residential Demand f o r E n e r g y : R e p o r t t o t h e E l e c t r i c Power R e s e a r c h I n s t i t u t e , mimeo, J u n e , 1976. T r e b i n g , H a r r y H. (ed.) ( 1 9 7 3 ) , E s s a y s 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 , M i c h i g a n S t a t e University, East Lansing, Michigan. Iroxel, and  Emery (1947), Economics Company, I n c . , New York.  Turvey, Ralph (1968), E l e c t r i c i t y Supply,  of P u b l i c  Optimal Pricing George A l l e n and  U t i l i t i e s , Rinehart  and Investment in Unwin, L t d . , London.  Turvey, R a l p h ( 1 9 7 1 ) , E c o n o m i c A n a l y s i s and George A l l e n and Unwin L t d . , L o n d o n .  Public  Enterprises.  Turvey, Ralph (1976), " A n a l y z i n g the Marginal Cost S u p p l y " , i n Land E c o n o m i c s , V o l . 52, No. 2, May, Tussing, Arlon R. (1976), "An I n k l i n g o f t h e Long N o r t h e r n P e r s p e c t i v e s , V o l . 4. No. 4.  of Water 1976. Journey",  U.S.A., Office of Utilities Programs, Federal Energy Administration (1975), The C h a l l e n g e o f L o a d Management: A Convergence of D i v e r s e I n t e r e s t s , Conservation Paper No. 24, W a s h i n g t o n , D . C , June, 1975. Uri,  Noel D. (1975), Towards an Efficient Allocation of E l e c t r i c a l E n e r g y ; An E s s a y i n A p p l i e d Welfare Economics, L e x i n g t o n Books, T o r o n t o .  Weisbeck, Don ( 1 9 7 6 ) , "A M e t h o d o l o g i c a l and C o s t C o m p a r i s o n o f Alternative Analyses of Exploiting Canadian and U.SF r o n t i e r N a t u r a l Gas R e s o u r c e s " , M.A. T h e s i s , Department o f Economics, University of British Columbia, Vancouver, September, 1976. Weitzman, M a r t i n L. ( 1 9 7 6 ) , "The O p t i m a l Development o f R e s o u r c e P o o l s " , J o u r n a l o f E c o n o m i c T h e o r y , V o l . 12, No. 3, June, 1976.  126  Menders, J . T . , ( 1 9 7 6 ) , "Peak Load P r i c i n g i n t h e E l e c t r i c Utility Industry", The B e l l J o u r n a l o f E c o n o m i c s , V o l . 7. No. 1, S p r i n g , 1976. Menders, John T. and L.D. T a y l o r (1976), Experiments in 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 U s e r s , mimeo. U n i v e r s i t y o f A r i z o n a . Wilson, J.W. (1971), "Residential Demand for Electricity", Q u a r t e r l y Review o f E c o n o m i c s and B u s i n e s s , V o l . 11, No. 1, S p r i n g , 1971. W i l s o n , J o h n A. ( 1 9 7 4 ) , " E l e c t r i c U t i l i t y R a t e s and F u t u r e Power Demand T r e n d s i n B r i t i s h C o l u m b i a : A S t u d y P r e p a r e d f o r t h e B.C. Hydro and Power A u t h o r i t y " , mimeo. Wilson, H.W. (1974a), "Electricity Consumption: R e q u i r e m e n t s , Demand E l a s t i c i t y and R a t e D e s i g n " , J o u r n a l o f A g r i c u l t u r a l E c o n o m i c s . May, 1974.  Supply American  APPENDIX A B.C. HYDRO AND POWER AUTHORITY STATEMENT OF INCOME FOR THE YEAR ENDED 31 MARCH 1976  $ 492,163,490  G r o s s 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 special subsidy Expenses: S a l a r i e s , wages and employee b e n e f i t s  157,000,822  M a t e r i a l s and s e r v i c e s  102,342,574  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  39,531 ,674  Depreciation  72,779,127  I n t e r e s t on d e b t  213,390,701  Less Interest charged to c o n s t r u c t i o n  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 special subsidy  (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  Net Income  32,600,000  $  1,297,425  I £8 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 6 0 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 5 0 0 kV (planned)  QUEEN CHARLOTTE ISLANDS  Vancouver Area M A J O R GENERATING PLANTS Alouette: Hydroelectric Burrard: Steam-Turbine Lake Buntzen: Hydroelectric  Port Mann: Gas-Turbine Ruskin: Hydroelectric Stave Falls: Hydroelectric  M A J O R 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  / This  appendix  update t h e b a s i c electrical  s e e k s t o s e r v e two p u r p o s e s . The f i r s t  r e s u l t s from  demand  forecast  the by  text  B . C .  discuss  a l t e r n a t i v e ways o f r e f o r m i n g  analyse  some o f t h e i m p l i c a t i o n s  The the  main  text  electrical  fleport.  The  of this  associated  given  average  produced a  did  forecast reflect  province unit  during  accounting  indicated than  costs Table  the e q u i v a l e n t  demand The that  in  these years.  and  1975 Task  percent  Force  1976 b a s e ,  8.1  and g r o s s o u t s t a n d i n g  8 0  in  f o r average  debt  in  C - 1 . As would be e x p e c t e d , t h e y r e s u l t s i n T a b l e 7 which u s e s  This  reform, but  about economic a c t i v i t y  The i m p l i c a t i o n s  Hydro  yielded  percent.  structure  was  during the B . C .  1976,  t h e same of  to  r e s u l t s b a s e d upon  o r 9.0  t o assume no r a t e  reduced expectations  i s to  a n n u a l compound g r o w t h r a t e  which, u s i n g  continued  recent  structure  i n t h e May  1976-1990 a v e r a g e a n n u a l g r o w t h r a t e  new  more  w i t h e a c h o f them.  ( s e e T a b l e 7 ) . I n September  a new f o r e c a s t  a  The s e c o n d  the r a t e  9.3 p e r c e n t o v e r t h e 1975-1990 p e r i o d , 1976-1990 p e r i o d  Hydro.  paper presented  demand f o r e c a s t forecasted  using  i s to  the  1990  the real are  are lower oriqinal  forecast. casic  economic  marginal price should  p r i n c i p l e of rate egual  structure  m a r g i n a l economic c o s t  design i s f o r each  B . C . Hydro's management h a s been r e l u c t a n t t o r e l e a s e t h e 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 e a c h c u s t o m e r c l a s s m a i n t a i n s t h e same s h a r e o f t o t a l demand as under t h e T a s k F o r c e p r o j e c t i o n and t h a t t h e s y s t e m l o a d f a c t o r a s s u m p t i o n o f 63.5 p e r c e n t c o n t i n u e s t o be a p p r o p r i a t e . 8 0  TABLE C-1 IMPACT ON B.C. HYDRO OF ALTERNATIVE RATE STRUCTURES NO RATE STRUCTURE CHANGE :  Growth Rate In Demand (%) (1976 - 1990) Average Accounting Cost (1976 M i l l s per KWH) (1976 - 1990)  8.1  17.5  Gross Debt Outstanding In 1990 12.3 (Billions of H i s t o r i c $)  RATE STRUCTURE CHANGE BASE CASE (MP=MC with AP=AC)'  FULL M.C.P. (MP=MC f o r a l l U n i t s )  5.4  5.4  16.0  13.7  8.6  1.1  131  customer  class.  appropriate  This  gives  intra-marginal  intra-marginal prices average class.  prices  were  of  the the  residential  general  and  flat  s u p p l e m e n t e d by  a  criteria  f o r the  a general  shift  the  larger The  likely  assumed  at  with  service  economic costs.  suggested  issue, although  income t a x standards.  an  most  In  i t may  on c a p i t a l  the  on  an  give r i s e used gains to  Ontario  consumption  method c h o s e n t o  were  be  cost,  satisfy  both  to  For t h i s c l a s s ,  more  text,  than a  returned initial  frequently  "valuation  from  i n other with  on  the  earlier.  criteria,  on  This  t o deal with  (1976c) has  returned  years  r e c o n c i l e t h e two  day"  to each customer  way  compliance  be  the  r e f e r e n c e date.  "pure"  the  double  t o c l a i m s of i n e q u i t y .  Hydro s t u d y  three  be  consumers  surpluses f o r the c l a s s  would be  the s u r p l u s e s from l a r g e u s e r s customer's  to  r a t e s t r u c t u r e would  bulk customers.  economically  approach  The  the  these c l a s s e s .  i n which t h e  cost pricing  the  would  the  of  m a r g i n a l economic  charge,  costs  the b a s i s o f h i s c o n s u m p t i o n perhaps  costs for  anticipated  i n i m p l e m e n t i n g a new  the f i f t y  accounting  marginal  new  that  marginal  reconciliation not  paper,  so  proposed  average accounting  was  the  c o s t s f o r each  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  present  a p p r o a c h was  adjusted  the  a  of  text of t h i s  be  of  the  ones w i t h i n e a c h o f  arise  to  classes,  rate  difficulties  however,  the  guestion  c l a s s e s a s a whole. T h e r e w o u l d , o f c o u r s e ,  marginal  is  In  criteria  small  proposed  full  price.  existing  accounting A  the  proximity  e c o n o m i c c o s t s and  difficult.  to  were e g u a l t o a v e r a g e a c c o u n t i n g  Because  e c o n o m i c and  rise  the  It  is,  matters,  from  anti-pollution suggested basis  Regardless  however, t h e  that  of  the  of  the  class  132  as  a  whole w i l l  will  induce  the  utility's  otherwise An and  be b e t t e r o f f s i n c e t h e  some t o r e d u c e t h e i r g r o w t h and  would have  alternative  revenue  higher  consumption,  keeping  on  customers*  marginal the  approach  would be  and  to ignore  apply  the  bills,  method, but  particularly  extreme, the  provincial  uses.  appropriate  than  new  Any  the  profits  industry  of  these  continued  electricity.  Over  would be  marginal compared  cost with  At t h e B.C.  government  within  the  result  each  could  Hydro  or  bulk  be  class.  and  4  billion  pricing  other and  scheme  case o f  no  put  to a variety to  to  the  technologies, in  of  1990  income  efficient  marginal  dollars and  of  facilitate  more e c o n o m i c a l l y  1981  of  price  of  additional  with  a  full  (assuming median e l a s t i c i t i e s )  as  rate s t r u c t u r e reform.  extreme, the used  question  reductions  historic  between  Because  addressed.  established  of  impact  c o u l d be t r a n s f e r r e d t o  provide  subsidization  class.  implementation  c o s t s , the  must be  year  u s e s would be  generated  the  to  marginal  each  by c u s t o m e r s t o e l e c t r i c i t y - c o n s e r v i n g  attract  taxes.  in  surplus profits  F o r example, a f u n d  conversion  they  accounting  could cause a l a r g e r  accounting  s u r p l u s r e v e n u e t h a t would  the  to  previous  the  a d m i n i s t r a t i v e and  economic c o s t s exceed  At one  what  8  a v o i d some o f t h e  problems of the  slowing  been. *  constraints  would  prices  thereby  a v e r a g e c o s t s below  e c o n o m i c c o s t s f o r a l l u n i t s of c o n s u m p t i o n This  marginal  new  profits  finance  could  expansion  be  retained  and/or  by  retire  T h i s i s a n a l a g o u s to t h e common p r o p e r t y problem where the economic rent i s d i s s i p a t e d from r i s i n g a v e r a g e c o s t s b e c a u s e each i n d i v i d u a l does n o t f a c e t h e f u l l m a r g i n a l 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 . 8 1  133  outstanding B.C.  Hydro  pricing those  yet further.  are a l s o from  paper. I n to  debt, thereby reducing  by  rate  1981  structure  we  these v a r i o u s  p r o p o s a l s on  the  c l a s s e s . These  column  dollars) with is  no  to  be  rate  order that a desired  to  be  B.C.  because  with  this  assumed  of these  used.  various  to review the e f f e c t s  are contained  total  revenue  f r o m e a c h c l a s s between  shows  from  average  the  column  i n the t e x t  average  of  by e a c h  i n Table  of  C-2.  (in  historic  1981  and  price i n  each  1990 class  by a common p e r c e n t a g e i n (which  c u m u l a t i v e revenue  (1))  and  under  of t h i s costs  accounting  o f l o w e r volumes  include  rate  the  setting  paper. M a r g i n a l p r i c e s a r e while  average  costs.  because  the  (with  Revenues  of a r e d u c t i o n  prices fall in  are both  average  accounting costs. The  economic  third costs  consumption adjustment in  the  is  revenues y i e l d e d  results  e g u a l t o m a r g i n a l economic  equated  unit  the t o t a l  of  margin) .  p e r c e n t a g e change  set  now  with  estimates are  revenues egual i t s c o s t s  column  used  contrasted  Hydro  to  marginal cost  of the reform  adjusted annually  Hydro's  next  procedures  turn  indicates derived  profit  The  effect  s t r u c t u r e r e f o r m . The  assumed  are  o f power  suggested i n the t e x t  t h e i m p a c t on B.C.  reform p o s s i b i l i t i e s ,  first  and  and t h e median e l a s t i c i t y  examined  customer  of this f u l l  shown i n T a b l e C-1,  the  Having  The  results  both c a s e s , t h e f u l l  be f e l t  rate  The  the average c o s t  column derived  in  each  shows t h e r e v e n u e i n the paper customer  effect  are a p p l i e d class,  to  the  final  column's  to a l l u n i t s  assuming  i n h e r e n t i n t h e median e l a s t i c i t y  contrast  i f the marginal  the  estimate.  results  which  of  demand This  is  depict  the  TABLE C-2  IMPACT ON CUSTOMERS OF ALTERNATIVE RATE STRUCTURES CUMULATIVE REVENUE (Millions of H i s t o r i c $) (1981 - 1990)  NO RATE STRUCTURE REFORM  CUSTOMER CLASS  RATE STRUCTURE REFORM BASE CASE (MP=MC with AP=AC, Median E l a s t i c i t i e s )  FULL M.C.P. FULL M.C.P. (MP=MC f o r a l l U n i t s , (MP=MC f o r a l l U n i t s , Median E l a s t i c i t i e s ) Zero E l a s t i c i t i e s )  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  effect cost  when t h e r e pricing.  substitution  i s no demand a d j u s t m e n t  These  possibilities  under t h e r e f o r m e d The on  total  the cost  fourth  figures  rate  cost  became a t t r a c t i v e  impact  the  very  residential  revenues  rise  general  in  classes  i n d i c a t e s t h a t they would almost under  more  realistic  with conversions reductions too  could This  on  how  for  be made b e t t e r  could  might combine t h e s e class  be  affected which  could  welfare  be used  applied  into  possible  be  principles.  by B.C.  bills  f o r the  extreme  condition  as  a  class  And by a s s i s t i n g b u l k  users  or tax reductions,  some r a t h e r  could  extreme  be a c c o m p l i s h e d .  d i f f e r e n t methods. set  with they  positions A  realistic  Average  prices  somewhere between t h e m a r g i n a l  costs.  reduce c o s t s  reform.  reality from  no  Some  of  the  resulting  t o r e d u c e B.C. H y d r o ' s d e b t w h i l e t h e r e s t  to  by t h e r a t e  turn  and  be g e n e r a t e d  electricity  grants  The  o f f under marginal c o s t p r i c i n g .  appendix has p r e s e n t e d  could  to  depend  impact, s i n c e i t  certainly benefit  through  e c o n o m i c and a v e r a g e a c c o u n t i n g surplus  customer  t o e l e c t r i c i t y - c o n s e r v i n g equipment and/or  i n their costs  each  i f no  i t s members.  under t h i s  assumptions.  rate s t r u c t u r e reform  approach  any  p r i c i n g , no demand r e s p o n s e ,  surplus  slight  and  the impact  for  t h e most e x t r e m e c o s t  marginal cost  from  marginal  on e a c h c u s t o m e r c l a s s would  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  assumes f u l l  Hydro. The  would r e p r e s e n t  full  structure.  column r e p r e s e n t s  benefits  t o the  f o r those c l a s s e s  O t h e r ways c o u l d  also  be  t h e t h e o r e t i c a l improvement  rate structures consistent,  with  adversely devised in social economic  136  D. APPENDIX D D.I  List  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 All All All All  V a r i a b l e Names E n d i n g V a r i a b l e Names E n d i n g Historic $ V a r i a b l e Names E n d i n g E l e c t r i c i t y U n i t s Are Stated  name C1KWH$76 C2KWH$76 COPFIX$ C0PFIX1$ COPVAB$ COP$76 COSTS$ DBULK DEPACC$H DEPREC$ DEXPOBT DGEN DGEOSS DGBOSSF DIND DLGSS DPEAK DPEAKF ORES DTOT DTOTF DWKPL EIN REQ FINREQB 1$ IDIST$76 IGEN$76 ITRF$76 ITRS$76 ITRS1$76 INT$ INTOLDB$ KELEC KELEC3  W i t h $76 A r e Measured I n M i l l i o n s Of 1976 $ With $H A r e M e a s u r e d I n M i l l i o n s Of With $ A r e Measured I n M i l l i o n s Of C u r r e n t $ M i l l i o n s Of KWH P e r Y e a r U n l e s s O t h e r w i s e  description Net C o s t P e r KWH G e n e r a t e d Cost Per K«H Generated F i x e d O p e r a t i n g C o s t s F o r C o m p l e t e System F i x e d O p e r a t i n g C o s t s To 230 KV L e v e l V a r i a b l e Operating Costs A n n u a l O p e r a t i n g C o s t s Of P r o j e c t s T o t a l O p e r a t i n g And C a p i t a l C o s t s Demand By B u l k C l a s s 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 F o r S c h o o l Tax P u r p o s e s D e p r e c i a t i o n Charges S a t i s f i e d E x p o r t Demand Demand By G e n e r a l C l a s s T o t a l Demand I n c l u d i n g L o s s e s F u t u r e T o t a l G r o s s Demand C o m m e r c i a l And I n d u s t r i a l Demand L o s s e s On I n t e g r a t e d System Maximum A n n u a l One-hour Demand (MW) F u t u r e Peak Demand R e s i d e n t i a l Demand T o t a l Demand Net Of L o s s e s F u t u r e T o t a l Net Demand West K o o t e n a y Power And L i g h t ' s I n c r e m e n t a l Demand F i n a n c i a l R e q u i r e m e n t s Not I n t e r n a l l y G e n e r a t e d ($) F i n a n c i a l R e q u i r e m e n t s To Be Met By Debt F i n a n c i n g { $ ) Investment Investment In D i s t r i b u t i o n F a c i l i t i e s Investment I n G e n e r a t i o n P r o j e c t s Investment In T r a n s f o r m a t i o n I n v e s t m e n t I n M a j o r T r a n s m i s s i o n And S u b - t r a n s m i s s i o n Projects Investment I n 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 T o t a l I n t e r e s t Charges A n n u a l I n t e r e s t Payments R e m a i n i n g On Bonds I s s u e d P r i o r To 1976 C o m p l e t e S t o c k Of E l e c t r i c i t y S u p p l y C a p i t a l A p p r o v e d A f t e r 1974 S t o c k O f E l e c t r i c i t y S u p p l y C a p i t a l ($76) To S e r v e L a r q e s t Customers  KELECU KPISC$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  S t o c k Of E l e c t r i c i t y S u p p l y C a p i t a l ($76) To S e r v e S m a l l e s t Customers Hew C o a l G e n e r a t i o n P l a n t I n 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 I n S e r v i c e New Gas T u r b i n e s I n S e r v i c e New Hydro P l a n t I n S e r v i c e T r a n s m i s s i o n And T r a n s f o r m a t i o n Plant In Service New T r a n s f o r m a t i o n Plant In Service M a j o r T r a n s m i s s i o n And S u b - t r a n s m i s s i o n Plant In Service T o t a l New P l a n t I n S e r v i c e S t o c k Of P o s t - 7 4 C o a l - f i r e d P l a n t I n S e r v i c e S t o c k Of P o s t - 7 4 D i s t r i b u t i o n P l a n t I n S e r v i c e S t o c k Of P o s t - 7 4 Gas T u r b i n e P l a n t I n S e r v i c e S t o c k Of P o s t - 7 4 H y d r o - e l e c t r i c P l a n t I n S e r v i c e New M i s c e l l a n e o u s P l a n t I n S e r v i c e F o r 230 KV L e v e l Customers A l l New T r a n s m i s s i o n And T r a n s f o r m a t i o n Plant S t o c k Of New M a j o r A s s o c i a t e d T r a n s m i s s i o n Projects In S e r v i c e A l l New T r a n s m i s s i o n And T r a n s f o r m a t i o n Plant In S e r v i c e T o S e r v e C u s t o m e r s At The 230 KV L e v e l Complete D i s c o u n t e d C o s t F o r E l e c t r i c i t y S u p p l i e d From P r o j e c t s A p p r o v e d A f t e r 1974 P r e s e n t V a l u e Of C o s t s A s s o c i a t e d W i t h S u p p l y i n g L a r g e s t Customers P r e s e n t V a l u e Of C o s t s A s s o c i a t e d W i t h S u p p l y i n g S m a l l e s t Customers P r e s e n t V a l u e Of A c t u a l E n e r g y S u p p l i e d (KWH) F o r P r o j e c t s A p p r o v e d A f t e r 1974 P r e s e n t V a l u e Of A c t u a l Peak Power Supplied(MW) F o r P r o j e c t s A p p r o v e d A f t e r 1974 P r e s e n t V a l u e O f A c t u a l E n e r g y P r o d u c e d (KWH) P r e s e n t V a l u e Of A c t u a l C a p a c i t y P r o d u c e d (MW) S t o c k Of P o s t - 7 5 New Bonds O u t s t a n d i n g S t o c k Of Debt I s s u e d P r i o r To 1976 S t i l l O u t s t a n d i n g End Of E a c h 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 C u s t o m e r s (M) A v e r a g e Bulk P r i c e ( $ ) Average Bulk P r i c e A v e r a g e E x p o r t P r i c e ($) Average Export P r i c e Average G e n e r a l Price<$) Average G e n e r a l P r i c e A v e r a g 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 ($) A v e r a g e I n d u s t r i a l And C o m m e r c i a l P r i c e C o m p l e t e D i s c o u n t e d C o s t ($76) P e r KWH A c t u a l Energy S u p p l i e d A v e r a g e R e s i d e n t i a l P r i c e ($) Average R e s i d e n t i a l P r i c e C o m p l e t e D i s c o u n t e d C o s t ($76) P e r Watt Of Peak Power S u p p l i e d A v e r a g e West K o o t e n a y Power And L i g h t P r i c e ( $ ) A v e r a g e 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 SCAP SCAPD SCAPH SCAPSURP SENER SENERB SENERBC SENERC SENERCAP SENERCC SENERG SENERGC SENERH SENERHC SENERK SENERKC SENERM SFPAYHTS TGRANTS TLAND TLOCAL TSCHOOL THATER YBULK YBU1KMCP IEXPORT YGEN YGENHCP YIHD YRES YRESMCP YSUEPMCP YTOT YTOTMCP YTOTSUBP YWKPL  D e s i r e d Reserve C a p a c i t y Margin 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?) D e s i r e d C a p a c i t y C a p a b i l i t y (MS) Hydro G e n e r a t i o n C a p a c i t y C a p a b i l i t y ( M W ) S u 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 O v e r Desired Capacity Capability(MB) T o t a l Energy Generated A c t u a l Energy Produced At B u r r a r d B u r r a r d ' s Energy C a p a b i l i t y A c t u a l E n e r g y P r o d u c e d From Hat C r e e k C o a l T o t a l Energy C a p a b i l i t y Hat C r e e k C o a l C a p a b i l i t y A c t u a l E n e r g y P r o d u c e d From Gas T u r b i n e s Gas T u r b i n e s E n e r g y C a p a b i l i t y A c t u a l E n e r g y P r o d u c e d From H y d r o S o u r c e s Hydro-generated Energy C a p a b i l i t y A c t u a l E n e r g y P r o d u c e d From E a s t K o o t e n a y C o a l E a s t K o o t e n a y C o a l Energy C a p a b i l i t y A c t u a l E n e r g y I m p o r t e d From O t h e r U t i l i t i e s A n n u a l S i n k i n g Fund Payment And A d d i t i o n a l F u n d s R e q u i r e d F o r Bonds M a t u r i n g B e f o r e 1982 'Grants'($) Land T a x e s ( $ ) A l l L o c a l Taxes{$) S c h o o l T a x e s ($) Water L i c e n c e C o s t s { $ ) Revenue From B u l k S a l e s { $ ) Revenue From B u l k S a l e s Under F u l l M.C.P.{$) Revenue From E x p o r t S a l e s ($) Revenue From G e n e r a l S a l e s {$) Revenue From G e n e r a l S a l e s Under F u l l M.C.P.{$) Revenue From C o m m e r c i a l And I n d u s t r i a l S a l e s { $ ) Revenue From R e s i d e n t i a l S a l e s { $ ) 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. ($) A d d i t i o n a l Net Income Under F u l l M.C.P. ($) T o t a l Revenues ($) T o t a l Revenue From S a l e s Under F u l l M.C.P. ($) T o t a l B.C. Hydro Net Income u n d e r F u l l M.C.P. ($) Revenue From WKPL S a l e s { $ )  139  0.1.2 Exogenous V a r i a b l e s All All All All  V a r i a b l e Names E n d i n g v a r i a b l e Names E n d i n g Historic $ V a r i a b l e Names E n d i n g E l e c t r i c i t y U n i t s Are Stated  name  With With  $76 A r e Measured I n M i l l i o n s Of 1976 $ $H A r e M e a s u r e d I n M i l l i o n s Of  With $ A r e Measured I n M i l l i o n s Of C u r r e n t $ M i l l i o n s Of KWH P e r Y e a r U n l e s s O t h e r w i s e  description  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 B u l k C l a s s DBULKF F u t u r e Demand By B u l k C l a s s DGEN Demand By G e n e r a l C l a s s DGENF F u t u r e Demand By G e n e r a l C l a s s DGBOSSF F u t u r e T o t a l G r o s s Demand DIND C o m m e r c i a l And I n d u s t r i a l Demand DLOSS L o s s e s On I n t e g r a t e d System DPEAKF F u t u r e Peak Demand <MW) ORES R e s i d e n t i a l Demand DRESF F u t u r e Demand By R e s i d e n t i a l C l a s s DTOTF F u t u r e T o t a l N e t Demand DWKPL West K o o t e n a y Power And L i g h t ' s I n c r e m e n t a l Demand DWKPLF F u t u r e Demand By WKPL. GENRED G e n e r a l 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$...IDCG50$ Annual I n t e r e s t During C o n s t r u c t i o n F o r Each G e n e r a t i o n P r o j e c t IDCT1$...IDCT45$ Annual I n t e r e s t During C o n s t r u c t i o n F o r Each A s s o c i a t e d M a j o r T r a n s m i s s i o n P r o j e c t IDST1$76 I n v e s t m e n t I n D i s t r i b u t i o n F a c i l i t i e s F o r New C u s t o m e r s IDST2$76 I n v e s t m e n t I n D i s t r i b u t i o n F a c i l i t i e s F o r Growth By E x i s t i n g Customers IG1$...IG50$ I n v e s t m e n t On Each G e n e r a t i o n P r o j e c t IGEN$ Investment In G e n e r a t i o n P r o j e c t s IGEN$76 Investment In G e n e r a t i o n P r o j e c t s IMISC$76 I n v e s t m e n t In O t h e r E l e c t r i c P l a n t INTRED$H R e d u c t i o n s In I n t e r e s t C h a r g e s Due To M a t u r i n g Of Bonds I s s u e d B e f o r e 1976 I T 1 $ . . . I T45$ I n v e s t m e n t On Each M a j o r A s s s o c i a t e d Transmission Project ITRF1$76 Investment I n 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 ITRF2$76 I n v e s t m e n t In S u b - t r a n s m i s s i o n T r a n s f o r m a t i o n ITRS1$ I n v e s t m e n t In M a j o r 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 ITRS1$76 I n v e s t m e n t In M a j o r 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 Investment In N o n - a s 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 s ITRS2$76 I n v e s t m e n t In S u b - t r a n s m i s s i o n L i n e s ITRS3$76 New C o a l G e n e r a t i o n P l a n t I n S e r v i c e KPISC$H S t o c k Of P o s t - 7 4 Hat C r e e k P l a n t In S e r v i c e KPISC$76 KPISG$H New Gas T u r b i n e s I n S e r v i c e  KPISGS76 KPISB$H KPISH$76 KPISK$76  S t o c k Of P o s t - 7 4 Gas T u r b i n e F a c i l i t i e s I n S e r v i c e New Hydro P l a n t I n S e r v i c e S t o c k Of P o s t - 7 4 H y d r o - e l e c t r i c P l a n t I n S e r v i c e S t o c k Of P o s t - 7 4 E a s t K o o t e n a y C o a l - f i r e d P l a n t I n Service KPIST$76 a l l New T r a n s m i s s i o n and T r a n s f o r m a t i o n P l a n t KPIST 1$H New M a j o r T r a n s m i s s i o n P l a n t I n S e r v i c e KPIST2$H New N o n - a s s o c i a t e d M a j o r T r a n s m i s s i o n and S u b t r a n s Mission Plant In S e r v i c e KPSTF$76 New T r a n s f o r m a t i o n P l a n t I n S e r v i c e KPST1$76 New M a j o r T r a n s m i s s i o n P l a n t I n S e r v i c e KPST2$76 New N o n - a s s o c i a t e d T r a n s m i s s i o n and S u b - t r a n s m i s s i o n Plant In Service KPST3S76 A l l New T r a n s m i s s i o n And T r a n s f o r m a t i o n P l a n t I n S e r v i c e To S e r v e C u s t o m e r s A t The 230 KV L e v e l KPST4$76 S t o c k Of New S u b - t r a n s m i s s i o n T r a n s f o r m a t i o n P l a n t I n Service LMWOSF$ S h o r t f a l l I n S i n k i n g Fund F o r Bonds M a t u r i n g A f t e r 198 L0LDM$H S t o c k Of Debt I s s u e d P r i o r To 1976 T h a t M a t u r e s Each Year NOC0ST Number Of E l e c t r i c i t y C u s t o m e r s (M) PEXOG Price Levels QSTART S w i t c h I n d i c a t i n g E n e r g y P r o d u c t i o n 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 C a p a c i t y C a p a b i l i t y Of B u r r a r d P l a n t (MW) SCAPC C a p a c i t y C a p a b i l i t y Of Hat C r e e k 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 Capacity Capability(MW) SCAPG C a p a c i t y C a p a b i l i t y Of Gas T u r b i n e P l a n t s (MW) SCAPH C a 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 C a p a c i t y C a p a b i l i t y O f E a s t K o o t e n a y P l a n t s (MW) SEC NEW New E n e r g y C a p a b i l i t y SENCAC1 Hat C r e e k ' s C a p a b i l i t y At Y e a r End SENCAPF Future Expected Energy C a p a b i l i t y SENERBAC B u r r a r d ' s Energy C a p a b i l i t y SENERCAC A v e r a g e Hat C r e e k C o a l C a p a b i l i t y T h r o u g h o u t Year SEN ERGAC A v e r a g e Gas T u r b i n e s Energy C a p a b i l i t y Throughout Year SENERHAC A v e r a g e E n e r g y C a p a c i t y T h r o u g h o u t Year From Hydro s o u r c e s D u r i n g A v e r a g e R a i n f a l l P e r i o d s SENERHCC A v e r a g e E n e r g y C a p a c i t y T h r o u g h o u t Year From Hydro S o u r c e s D u r i n g 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 E a s t Kootenay C o a l Energy C a p a c i t y Throughout Year SENGAC1 Gas T u r b i n e s E n e r g y C a p a b i l i t y A t Y e a r End SENHAC1 Energy G e n e r a t i o n C a p a c i t y From H y d r o - e l e c t r i c S o u r c e s D u r i n g A v e r a g e R a i n f a l l P e r i o d A t Year End SENHCC1 Energy G e n e r a t i o n C a p a c i t y From H y d r o - e l e c t r i c S o u r c e s D u r i n g C r i t i c a l R a i n f a l l P e r i o d A t End Of Ea< Year SENKAC1 Energy G e n e r a t i o n C a p a c i t y From E a s t K o o t e n a y C o a l At Y e a r End STARG1...STARG50 A p p r o v a l D a t e s For Each G e n e r a t i o n P r o j e c t  141  START 1. . STPNOM TOTSED  START45 A p p r o v a l D a t e s F o r Each A s s o c i a t e d M a j o r Transmission Project N o m i n a l R a t e Of S o c i a l Time P r e f e r e n c e T o t a l Demand Change Due T o P r i c e Change  142  D.I.3 Values no.  Coefficients Shown Are T h o s e I n The B a s e C a s e value  1849 1850  63.5 0.057  1851 1852 1853  1.2 1. 1 .0049  1854  .024  1855  .0108  1856  .0095  1857  .033  1858 1859 1860 1861 1862  .015 .01 .0005 .00025 .0055  1863  .0059  1864  .0187  1865  .03  1866 186 7  0.0 .88  1868 1869 1870  .94 227.69 .01  1871  .0175  1872  . 1  1873  .5  1874 1875  .0143 .0286  1876  .0222  1877  .0272  1878 1879 1880  .02 .0095 1.25  description A n n u a l L o a d F a c t o r ( c o n v e r t s MM KWH To MW) S w i t c h - I n d i c a t e s D e p r e c i a t i o n Used F o r E c o n o m i c Analysis I n t e r e s t During Construction For Transmission P r o j e c t s 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 A n n u a l F i x e d 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 Hydro Facilities Annual F i x e d Operating Cost C o e f f i c i e n t For C o a l Facilities A n n u a l F i x e d 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 Gas Facilities Annual 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 For T r a n s m i s s i o n 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 Annual 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 For D i s t r i b u t i o n Facilities A v e r a g e M i l l Hate I n 1976 R a t e Used I n D e t e r m i n i n g A n n u a l * g r a n t s * Water L i c e n c e C h a r g e ($MM/MW) Water L i c e n c e C h a r g e ($/KWH) A n n u a l V a r i a b l e 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 Hat C r e e k Coal Generation Annual V a r i a b l e Operating Cost C o e f f i c i e n t F o r East Kootenay C o a l G e n e r a t i o n Annual V a r i a b l e Operating Cost C o e f f i c i e n t F o r B u r r a r d Generation | g a s - o i l P r i c e P a r i t y ) A n n u a l V a r i a b l e 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 Gas Turbines Demand Shock I n t e g r a t e d E l e c t r i c P l a n t I n S e r v i c e : t o t a l B.C. Hydro Plant In Service Net Out I n t e r e s t E a r n e d From S i n k i n g Fund I n v e s t m e n t s G r o s s I n t e r e s t On Debt F o r B.C. Hydro I n 1975 P e r c e n t Of O u t s t a n d i n g Pre-1976 Debt C o n t r i b u t e d A n n u a l l y To S i n k i n g Fund P e r c e n t Of O u t s t a n d i n g P o s t - 1 9 7 5 Debt C o n t r i b u t e d A n n u a l l y To S i n k i n g Fund A n n u a l N o m i n a l I n t e r e s t Rate F o r B.C. Hydro P o s t - 1 9 7 5 Debt P r o p o r t i o n Of E l e c t r i c i t y B..C. H y d r o S e e k s To E x p o r t Actually Purchased I n v e r s e Of E x p e c t e d S e r v i c e L i f e Of Hydro F a c i l i t i e s I n v e r s e O f E x p e c t e d S e r v i c e L i f e Of C o a l And Gas T u r b i n e Facilities I n v e r s e Of E x p e c t e d S e r v i c e L i f e Of T r a n s m i s s i o n Facilities I n v e r s e Of E x p e c t e d S e r v i c e L i f e O f D i s t r i b u t i o n Facilities A v e r a g e Import P r i c e Of E l e c t r i c i t y E x p o r t P r i c e Of E l e c t r i c i t y R e a l C a p i t a l C o s t A d j u s t m e n t F o r New G e n e r a t i o n  143  1881 1882 1883 1885 1886 1887 1888 1889 1890 1891 1894 1895 1900 1901 1902 1903 1904 1905 1906 1907 1908 1909 1910 191 1 1912 1913 1914 1915 1916 1917 1918 1919 1920 1921 1922 1923 1931 1932 1933 1934 1935 1936 1937 1938 1939 1940 1941 1942 1943 1944 1945 1951 1952 1953 1954  1.0225 1.02 1.02 63.5 76. 0.0 0.0 .075 0.0 .075 .03 0.0 1.39 1.39 1.39 1. 39 1. 39 1.39 1. 39 1. 39 1.53 1.53 1.53 1. 47 1.39 1. 47 1.47 1.39 1.39 1.53 1..53 1.47 1.47 1.47 1.47 1.39 1.39 1.39 1.39 1.39 1.47 1.47 1.47 1.47 1. 47 1.47 1.47 1. 47 1. 47 1. 47 1.39 1.39 1.39 1. 39  Facilities R e a l A n n u a l Sage Rate A d j u s t m e n t Real Annual C o a l Value Adjustment Real Annual G a s / o i l Value Adjustment A n n u a l Load F a c t o r F o r Demand Shock G r o s s Demand Shock - S e t I n Model I n i t i a l Y e a r O f Demand Shock Demand Shock I n 1976 O n l y Shock I n Number Of C u s t o m e r s P r i v a t e A f t e r - t a x R e a l C o s t O f Funds I n v e r s e Of S e r v i c e L i f e Used - S e t I n Model 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 C o r p o r a t i o n Tax I n O t h e r I n d u s t r y S e t I n Model - S u p p l y A p p r o v a l Date Shock A d j u s t m e n t From $74 E s t i m a t e To $76 I n c l u d i n g C o r p o r a t e O v e r h e a d F o r Each Group Of M a j o r G e n e r a t i o n And T r a n s m i s s i o n P r o j e c t s Continued  144  1956 1.39 1958 1.39 1959 1.39 1960 1.39 197 1 1.39 1972 0.0 1981 1.39 1986 1.39 1988 1. 39 1990 1.39 1994 1.39 1995 1.39 2000 .062 2001 .026 2002 .012 200 3 .0 36 200 4 1.25 2005 .019 2006 .017 2007 0.0 2010 0.0 2011 0.0 2012 0.0 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023  17.0 26.0 15.0 24.0 10.0 22.0 0.4 0.6 0.8 Varies  2024 2025  0.0  R e a l R a t e Of I n f l a t i o n - S e t I n Model C o n t i n u a t i o n Of C a p i t a l C o s t A d j u s t m e n t F a c t o r s F o r E a c h Group O f M a j o r G e n e r a t i o n And T r a n s m i s s i o n P r o j e c t s  I n v e s t m e n t I n N o n - a s s o c i a t e d M a j o r T r a n s m i s s i o n ($MM/MW) I n v e s t m e n t I n S u b - t r a n s m i s s i o n L i n e s ($MM/MW) I n v e s t m e n t I n T r a n s m i s s i o n T r a n s f o r m a t i o n ($MM/MW) I n v e s t m e n t I n 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 <$MM/MH) I n v e s t m e n t I n D i s t r i b u t i o n P e r New Customer($MM/M C u s t ) I n v e s t m e n t I n D i s t r i b u t i o n P e r C u r r e n t C u s t . ($MM/MW) I n v e s t m e n t I n O t h e r E l e c t r i c P l a n t ($MM/MK»H) S w i t c h - i n d i c a t e s C r i t i c a l R a i n P e r i o d I f Not Z e r o Switch- Indicates Unit For Marginal Cost Analysis 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 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 Effects Old Marginal P r i c e For R e s i d e n t i a l Class New M a r g i n a l P r i c e F o r R e s i d e n t i a l C l a s s O l d Average M a r g i n a l P r i c e F o r G e n e r a l C l a s s New M a r g i n a l P r i c e F o r G e n e r a l C l a s s O l d Combined M a r g i n a l P r i c e F o r B u l k C l a s s New Combined M a r g i n a l P r i c e F o r B u l k C l a s s A b s o l u t e 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 A b s o l u t e 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 A b s o l u t e 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 B a s i c Net Demand R e a d j u s t m e n t C o e f f i c i e n t S e t In Model - P r e s e n t N e t Demand R e a d j u s t m e n t Coefficient S e t I n Model - F u t u r e Net Demand R e a d j u s t m e n t Coefficient 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 A p p r o v a l D a t e s To Follow  145  D.1.4  no. 1 2 3 4 5 6 7 3 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45  Generation  and T r a n s m i s s i o n P r o j e c t s  description Kootenay Canal(1-2) K o o t e n a y C a n a l (3-4) M i c a (1-2) Mica{3) M i c a (4) S i t e One (1-3) S i t e One (4) Seven M i l e (1-3) R e v e l s t o k e (1-2) Revelstoke(3) Revelstoke(4) Kootenay D i v e r s i o n Shrum(10) McGregor D i v e r s i o n ( w i t h o u t S i t e C) McGregor D i v e r s i o n ( w i t h S i t e C) Mica (5) Mica{6) Revelstoke(5) Revelstoke(6) Seven M i l e ( 4 ) S i t e C{1-2) S i t e C{3) S i t e C{4) V a n c o u v e r I s l a n d Gas T u r b i n e s ( 1 ) V a n c o u v e r I s l a n d Gas T u r b i n e s ( 2 ) E x t r a Gas T u r b i n e s ( 1 5 0 MH) E x t r a Gas T u r b i n e s ( 3 0 0 M B ) E x t r a Gas T u r b i n e s ( 6 0 0 MB) Hat C r e e k ( 1 ) Hat Creek{2) Hat C r e e k ( 3 ) Hat C r e e k ( 4 ) Hat C r e e k ( 5 ) Hat C r e e k ( 6 ) Hat C r e e k ( 7 ) Hat C r e e k ( 8 ) East Kootenay(1) 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 IF IF IF IF IF IF IF IF IF IF IF IF IF IF IF IF  - RESIDENTIAL DEMAND NTIME= 75 THEN DRES= 5600. *A (2023) NTIME= 76 THEN DRES= 6100. *A(2023) NTIME= 77 THEN DRES= 6700. *A (2023) NTIME= 78 THEN DRES= 7500. *A (2023) NTIME= 79 THEN DRES= 8400. *A (2023) NTIM E= 80 THEN DRES= 9200. A(2023) NTIME= 81 THEN DRES= 10000 « *A (2023) NTIME= 82 THEN DRES= 11000 *A (2023) NTIME= 83 THEN DRES= 12000 *A (2023) NTIME= 84 THEN DRES= 13100 • *A (2023) NTIME= 85 THEN DRES= 14500 * *A(2023) NTIME= 86 THEN DRES= 15800 • *A (2023) NTIME= 87 THEN DRES= 17000 • *A (2023) NTIME= 88 THEN DRES= 18300 *A (2023) NTIME= 89 THEN DRES= 19700 • *A (2023) NTIME>=90 THEN DRES=21000.*A(2023)  DGEN IF IF IF IF IF IF IF IF IF IF IF IF IF IF IF IF  - GENERAL CLASS DEMAND NTIME=75 THEN DGEN=7000. *A(2023) NTIME=76 THEN DGEN=8100. *A (2023) NTIME=77 THEN DGEN=900O. *A{2023) NTIME=78 THEN DGEN=10OO0 .*A{2023) NTIME=79 THEN DGEN=11100 . *A{2023) NTIME=80 THEN DGEN=122G0 .*A (2023) NTIME=81 THEN DGEN=13300 .*A (2023) NTIME=82 THEN DGEN=14400 .*A (2023) NTIME=83 THEN DGEN=15500 .*A{2023) NT.IME=84 THEN DGEN=16700 .*A (2 023) NTIME=85 THEN DGEN=18000 .*A (2023) NTIME=86 THEN DGEN=19500 .*A (2023) NTIME=87 THEN DGEN=21000 . *A (2 023) NTIME=88 THEN DGEN=22500 .*A (2023) NTIME=89 THEN DGEN=24Q00 .*A (2023) NTIME>=90 THEN DGEN=2550 0.*A(2023)  DBOLK - BULK CLASS DEMAND I F NTIME=75 THEN DBULK= 7200. *A (2023) I F NTIME=76 THEN DBULK= 8400. *A(2023) I F NTIME=77 THEN DBULK= 9500. *A (2 023) I F NTIME=78 THEN DBULK= 10500 .*A{2023) I F NTIME=79 THEN DBULK= 11600 •*A(2023) IF NTIME=80 THEN DBULK= 12800 .*A{2023) I F NTIME=81 THEN DBULK= 14200 .*A{2023) I F NTIME=82 THEN DBULK= 15600 .*A(2023) I F NTIME=83 THEN DBULK= 17300 .*A{2023) IF NTIME=84 THEN DBULK= 18900 . *A(2023) I F NTIME=85 THEN DBULK= 20400 .*A(2023) I F NTIME=86 THEN DBULK= 22200 . *A{2023) I F NTIME=87 THEN DBULK= 24400 .*A{2023) I F NTIHE=88 THEN DBULK= 26600 . *A{2023) I F NTIME=89 THEN DBULK= 28900 .*A{2023) I F NTIME>=90 THE N DBUXK = 3150 0.*A (2023) DIND - COMMERCIAL AND INDUSTRIAL DIND=DGEN*DBUI»K  DEMAND  DWKPL - WEST KOOTE NAY POWER AND LIGHT'S INCREMENTAL DEMAND IF NTIME=75 THEN DWKPL=0. I F NTIME=76 THEN D1KPL=0. I F NTIME=77 THEN DWKPL=200.*A(2023) I F NTIME=78 THEN DWKPL=400.*A(20 23) I F NTIME=79 THEN DWKPL=700.*A(2023) I F NTIME=80 THEN DWKPL=1000.*A(2023) I F NTIME=81 THEN DWKPL= 1300. *A (2023) I F NTIME=82 THEN DWKPL=1700.*A(2023) I F NTIME=83 THEN DWKPL=2100.*A{2023) I F NTIME=84 THEN DWKPL=2500. *A(2023) I F NTIME=85 THEN DWKPL=2800.*A (2023) I F NTIME=86 THEN DWKPL=3000.*A (2023) I F NTIME=87 THEN DWKPL=3300.*A{202 3) I F NTIME=88 THEN DWKPL=3600. *A (2023) I F NTIME=89 THEN DWKPL=3800. *A{2023) I F NTIME>=90 THE N D « K P L = 4 1 0 0 . * A { 2 0 23) NOCUST - NUMBER OF ELECTRICITY CUSTOMERS I F NTIME=75 THEN NOCUST=859. I F NTIME=76 THEN NOCUST=898.  147  CO  I F NTIME= 77 THEN NQC0ST= 939. I F NTIME= 78 THEN NOCOST= 982. I F NTIME= 79 THEN NOCUST= 1027. I F NTIME= 80 THEN NOCUST= 1074. I F NTIME= THEN NOC0ST= 1123. I F NTIME= 82 THEN NOCOST= 1175. I F NTIME= 83 THEN NOCGST= 1229. I F NTIME= 84 THEN NOCUST= 1285. I F NTIH E= 85 THEN NOCUST= 1343. I F NTIME= 86 THEN NOCOST= 1405. I F NTIME= 87 THEN NOCUST= 1469. IF NTIME= 88 THEN NOCOST= 1536. I F NTIME= 89 THEN NOC0ST= 1607. I F HTIHE> =90 THEN NOC0ST=1680. DRESF - EXPECTED RESIDENTIAL DEMAND SIX YEARS I F NTIME=75 THEN DRESF=10000.*A(2024) I F NTIME=76 THEN DRESF=11000.*A (2024) I F NTIME=77 THEN DRESF=12000.*A(2024) I F NTIME=78 THEN DRESF=13100.*A(2024) I F NTIME=79 THEN DRESF=14500.*A(2024) IF NTIME=80 THEN DRESF=15800.*A (2024) I F NTIME=81 THEN DRESF=17000.*A(2024) I F NTIME=82 THEN DRESF=18300.*A(2024) I F NTIME=83 THEN DRESF=19700-*A (2024) I F NTIME>=84 THEN DRESF=21000. *A (2024)  HENCE  DGENF - EXPECTED GENERAL DEMAND SIX YEARS HENCE I F NTIME=75 THEN DGENF=13300.*A(2024) I F NTIME=76 THEN DGENF=14400.*A (2024) I F NTIHE=77 THEN DGENF=15500.*A(2024) IF NTIME=78 THEN DGENF=16700.*A(2024) I F NTIME=79 THEN DGENF=18000.*A (2024) I F NTIME=80 THEN DGENF=19500.*A(2024) IF NTIME=81 THEN DGENF=2 1000.'"A (2024) I F NTIME=82 THEN DGENF=22500.*A(2024) I F NTIME=83 THEN DGENF=24000.*A(2024) I F NTIME>=84 THEN DGENF=25500.*A (2024) DBULKF - EXPECTED BULK DEMAND SIX YEARS HENCE I F NTIME=75 THEN DBULKF=14200.*& (2024) I F NTIHE=76 THEN DBOLKF= 15600.*A (2024) I F NTIME=77 THEN DBULKF=17300.*A(2024) I F NTIME=78 THEN DBDLKF= 18900. *A (2 024) I F NT.IME=79 THEN DBULKF= 20400. *A (2024) IF NTIME=80 THEN DBULKF=22200.*A (2024) I F NTIME=81 THEN DB0LKF=24400.*A (2024) IF NTIME=82 THEN DBULKF=26600.*A (2024) I F NTIME=83 THEN DBOLKF=28900.*A (2024) I F NTIME>=84 THEN DBOLKF=31500.*A(2024) DHKPL - EXPECTED HKPL DEMAND SIX YEARS HENCE I F NTIME=75 THEN DHKPLF=1300.*A(2024) I F NTIME=76 THEN DWKPLF=1700.*A(2024) I F NTIME=77 THEN DwKPLF=2100.*A(2024) I F NTIME=78 THEN DWKPLF=2500.*A(2024) I F NTIME=79 THEN DWKPLF=2800.*A(2024) I F NTIME=80 THEN DWKPLF=3000.*A(2024) I F NTIME=81 THEN DWKPLF=3300.*A(2024) I F NTIME=82 THEN DHKPLF=3600.*A(2024)  IF IF  NTT 13E= 83 THEN DHKPLF=3800.*A{2024) 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 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. I F A (2025) NOT= 1. THEN GO TO 5  AND TRANSMISSION  PROJECTS  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 I F NTIWE>75 THEN GO TO 10 INCORPORATE REAL CAPITAL COST 1906) =A1(1906) *A (1880) A 1907) =A ;1907) *A ;1880) A 1908) =A (1908) *A (1880) A I1909) =A [1909) *A (1880) A (1910) = A [1910) *A (1880) [ 1911)=A i 1911) *A ;1880) A| 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 1917) *A \[1880) A ,1917) I A (1918) = A (1918) *A [1880) A I'1919) =A i 1919) *A ;1880)  ADJUSTMENT  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) ' 1940)=A ;1940) *A<(1880) A1 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 F I X E D COSTS (WAGE INCREASES) A (1855) =.0045+{ (A{1855) -.0045) *A{1881) ) TRANSMISSION AND TRANSFORMATION - ANNUAL FIXED COSTS A ( 1 8 5 6 ) = . 0 0 3 + ( ( A ( 1 8 5 6 ) - .003) *A{1881) )  (HAGE INCREASES)  DISTRIBUTION - ANNUAL FIXED COSTS (HAGE INCREASES) A (1857) =.002+ ({A (1857) -.002) *A (1881) ) COAL - ANNUAL VARIABLE COSTS DUE TO ENERGY A (1862) =A (1862) *A(1882) A{ 1863) =A (1863) *A(18 82) GAS/OIL - ANNUAL VARIABLE COSTS A( 1864)=A{1864) *A(1883) A(1865)=A{1865) *A (1883)  SUBROUTINE  DEMAND  (ENERGY INCREASES)  DEMAND  EQUATIONS  DRES - RESIDENTIAL DEMAND, PRICE ADJUSTED I F A(2012) NOT= 1. THEN GO TO 2 I F NTIME<77 THEN GO TO 2 IF  VALUE INCREASES  NTIME=77 THEN DRES= (1.-.2* (1.-RESRED) ) *DRES  IF  NTIME=78 THEN DRES= (1. -. 4* (1.-RESRED) ) *DRES  IF  NTIME=79 THEN DRES= ( 1 . - . 6* ( 1.-RESREB) ) *DRES  I F 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 I F RTIME=76. THEN DRES= DRES•A(1888) DGEN - GENERAL CLASS DEMAND, PRICE ADJUSTED I F A(2012) NOT= 1. THEN GO TO 4 I F 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 I F 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  IF  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  151  DIND - COMMERCIAL  AND IND 0 S TBI AL DEMAND  152  7 DIND=DGEN + DBULK HEBE I P DEMAND SHOCK  INTBODOCED  I F RTIME>=A{1887) THEN DIND=DIND+A (1866) DWKPL - WEST KOOTENAY POWER AND  LIGHT'S INCBEMENTAL  DffKPL=DWKPL NOCDST - NDMBEB OF ELECTRICITY CUSTOMERS I F BTIME<76. THEN NOCUST=NOCUST I F 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 I F A (1885) =0. THEN GO TO 10 I F RTIME<A(1887) THEN DPEAK=DGROSS/|A(1849)*.0876) I F 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 I F 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 I F NTIME=75 THEN PEXOG=1.83 I F NTIME=75 THEN J1L*PEXOG=1.67 I F NTIME=75 THEN J2L*PEXOG=1.5 I F NTIME=75 THEN J3L*PEXOG=1.4 I F NTIME=76 THEN PEXOG=2.11 I F NTIME=76 THEN J2L*PEXOG=1.67 I F NTIME=76 THEN J3L*PEXOG=1.5 I F NTIME=77 THEN PEXOG=2.32 I F NTIME=77 THEN J3L*PEXOG=1.67 I F NTIME=78 THEN PEXOG=2.55  DEMAND  I F NTIME=79 THEN PEXOG=2.81 IF NTIME=80 THEN PEXOG=3.09 I F 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 OF BONDS ISSUED BEFORE 1976 I F NTIME=75 THEN INT8ED$H= 0. I F NTIME=76 THEN INTRED$H= .97 I F NTIME=77 THEN INTRED$H= 2. 61 I F NTIME=78 THEN INTREDSH= 0. I F NTIME=79 THEN INTRED$H= -72 I F NTIME=80 THEN INTRED$H= 5. 22 I F NTIME=81 THEN INTBED$H= 5. 64 I F NTIME=82 THEN INTRED$H= 15 .16 I F NTIME=83 THEN INTRED $H= 0. I F NTIME=84 THEN INT RED$B= 4. 31 I F NTIME=85 THEN INTRED$H= 4. 31 I F NTIME=86 THEN INTRED$H= 5. 26 I F NTIME=87 THEN INTRED$H= 5. 49 I F NTISE=88 THEN INTRED$H= 8. 2 I F NTIME=89 THEN INTRED$H= 10 .33 I F NTIME=90 THEN INTRED$H= 1. 42 LOLDMSH - STOCK OF DEBT ISSUED PRIOR TO EACH YEAR I F NTIME=75 THEN LOLDM$H=0. I F NTIME=76 THEN LOLDM$H=29.4 I F NTIME=77 THEN LOLDM$H=50.1 I F NTIME=78 THEN LOLDM$ H=0. I F NTIME=79 THEN LOLDM$H=18.4 I F NTIME=80 THEN LOLDM$H=59. 1 I F NTIME=81 THEN LOLDM$H=67.9 I F NTIME=82 THEN LOLDM$H=187, 3 I F NTIME=83 THEN LOlDM$H=0. I F NTIME=84 THEN LOLDM$H=50. I F NTIME=85 THEN LOLDM$H=50. I F NTIME=86 THEN LOLDM$H=124. 4 I F NTIME=87 THEN LOLDM$H=105.4 I F NTIME=88 THEN LOLDM$H=156.3 I F NTIME=89 THEN LOLDM$H=155.3 I F NTIME=90 THEN LOLDM$H=21.9  DUE TO  MATURING  1976 THAT MATURES  LMATWOSF - SHORTFALL IN SINKING FUND FOR BONDS MATURING LMATHOSF=0. I F NTIHE=82 THEN LMATWGSF=93.2 I F NTIME=86 THEN LMATWOSF=104.2 I F NTIME=87 THEN LMATWOSF=60.3 I F NTIME=88 THEN L M A T ¥ O S F = 8 1 . 9 I F NTIME=89 THEN L M A T ¥ O S F = 1 0 4 . 8 I F NTIME=90 THEN LMATHOSF=9.2 COVERAGE - INTEREST I F NTIME=75 THEN I F NTIME=76 THEN I F NTIME=77 THEN I F NTIME=78 THEN I F NTIME=79 THEN  COVERAGE POLICY COVERAGES. COVERAGES. COVERAGE^.04 COVERAGE-.08 COVERAGE^.12  COEFFICIENT  AFTER 1981  IF IF IF IF IF  NTIME=80 THEN COVERAGE^. 16 NTIME=81 THEN C0VERAGE=.2 NTIME=82 THEN COVERAGE=.24 NTIME=83 THEN COV ERAG E=.28 NTIME>=84 THEN CGVERAGE=.3  154  RESRED - RES. DEMAND CHANGE DOE TO MARG. PRICE CHANGE RESRED=(A{2013) + A ( 2 0 1 4 ) - (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 ( 2 0 1 6 ) - (A (2020) * (A (20 16)-A (20 15) ) ) ) / (A(2020) * ( A ( 2 0 1 6 ) - A ( 2 0 1 5 ) ) * A ( 2 0 1 5 ) + 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 TOTRED=((RESEED*DRES)+(GENRED*DGEN)+ (BULKRED*DBULK))/(DRES+DGEN+DBULK)  PRICE CHANGE  SUBROUTINE MCOST  CHECK FOR CRITICAL RAINFALL PERIOD I F A(2007) NOT= 0. THEN GO TO 20 SENERC - TOTAL NEW ENERGY GENERATION CAPABILITY DURING AVERAGE RAINFALL PERIOD SENERC=SENERHAC + SENERBAC+SENERCAC+ SENERKAC+SENERGAC796. GO TO 40 SENERC - TOTAL NEW ENERGY GENERATION CAPABILITY DURING CRITICAL RAINFALL PERIOD 20 SENERC=SENERHCC + SENERBAC+SENERCAC+SENERKAC+SEN ERGAC9. SCAP - TOTAL NEW CAPACITY CAPABILITY 40 SCAP=SCAPH+SCAPB*SCAPC+SCAPK+SCAPG-5413. I F A(2010)>30. THEN GO TO 50 I F A (2011)>10. THEN GO TO 50 HERE I F A HYDRO PROJECT NLIFE - EXPECTED PHYSICAL L I F E 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 I F 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 I F 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 I F NEW PROJECT IS PRODUCING I F (SENERC+SCAP)>0. THEN QSTART=1.  ENERGY  NSTOP - TIME WHEN PROJECT'S L I F E IS OVER I F (QSTART-J1L*QSTART)=1. THEN NSTOP=NTIME+NLIFE-75 IF  K7>NSTOP THEN  COP$76=0.  RSTART - TIME WHEN NEW PROJECT BEGINS PRODUCING I F QSTART=0. THEN BSTABT=0., I F (QSTART-J1L*QSTART) = 1. THEN RSTART=RTIME  ENERGY  KPVELEC1 - PRESENT VALUE OF POTENTIAL ENERGY PRODUCED L I F E OF PROJECT BEING ANALYZED  (KWH) DURING  KPVELEC1=(1.+A(1894} ) *J1L*KPVELEC1+SENEEC*({1.+A{1894))**.5) KPVELEC2 - PRESENT VALUE OF POTENTIAL CAPACITY GENEBATED(MW) L I F E OF PROJECT BEING ANALYZED KPVELEC2=(1.*A(1894))*J1L*KPVELEC2+SCAP*((1.+A(189 4 ) ) * * . 5) I F QSTART=0. THEN GO TO 110 I F K7=NSTOP THEN  KPVELEC1=KPVELEC1/((1.*A(1894))**(K7-2))  I F 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 I F A(1850)>=1. THEN GO TO 120 HERE I F EXPONENTIALLY DECLINING DEPRECIATION CHARGE BASED ON AVERAGE ECONOMY-WIDE SESVICE L I F E  DUBING  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 ( 1 8 5 0 ) * (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 I F STRAIGHT-LINE DEPRECIATION CHARGE BASED ON ACTUAL L I F E 0 PROJECT BEING ANALYZED 120 I F A (1850) =1. THEN A ( 1 8 5 0 ) - R L I F E IF RSTART=0. THEN GO TO 125 I F 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 * ( J 1 I * K E L E C * K E L E C ) ) ) * ( (1.+A (1894) ) **.5) GO TO 200 HERE I F PROJECT L I F E FOR DEPRECIATION PURPOSES I S 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 I F QSTART=0. THEN GO TO 210 I F K7=NSTOP  THEN  IF  THEN KPV1$76=0.  K7>NSTOP  KPV1$76=KPV1$76/((1.+A{1894))**(K7-2))  PKWHCST1 - 1976$ PRESENT VALUE COST PER KWH PROJECT BEING ANALYZED IF  K7=8STOP THEN  I F K7>NSTOP PWCOST1 -  ENERGY CAPACITY FOR  PKWHCST1=KPV1$76/KPVELEC1  THEN PKWHCST1=0.  1976$ PRESENT VALUE COST PER WATT CAPACITY CAPABILITY FOR PROJECT BEING ANALYZED  IF  K7=NSTOP THEN  IF  K7>NSTOP  PWCOST1=KPV1$76/KPVELEC2  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 C A P A B I L I T Y . ENERGY AND/OR CAPACITY I S 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 I F A{2012) = 1. THEN DT OT F= R ES R ED* DR ES F • GENRED*DGENF*-BULKBED*DBULKF*DW KPLF I F A (2012) NOT= 1. THEN DTOTF=DRESF + DGENF+DBULKF + DWKPLF DTOTF - ADJUST EXPECTED TOTAL NET DEMAND BY DEMAND SHOCK I F 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 I F A{1885)=0. THEN GO TO 1 I F RTIME<(A(1887)—6.) THEN DPEAKF=DGROSSF/ (A(1849)*.0876) I F RTIME>= (A (1887)-6.) THEN DPEAKF=(DGROSSF-A( 1 8 8 6 ) ) / (A (1849) *.0876) + A (1886) / {A (1885) *.0876) GO TO 2 HERE I F DEMAND SHOCK HAS NO EFFECT ON PEAK DEMAND 1 I F RTIME< (A (1887)-6. ) THEN DPEAKF= DGROSSF/ (A(1849)*.0876) I F 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 - I N I T I A L I Z E NEW SECNEW=0.  ENERGY  SENCAPF - EXPECTED ENERGY  CAPACITY VARIABLE  GENERATION  CAPACITY SIX YEARS  158  HENCE ON  BASIS OF PROJECTS APPROVED TO DATE I F NTIME=75 THEN SENCAPF=41349. I F NTIME>75 THEN SENCAPF=J1L*SENCAPF+(.5*J1L*SECNEW) SCAPF - EXPECTED CAPACITY CAPABILITY SIX YEARS HENCE ON BASIS OF PROJECTS APPROVED TO DATE I F NTIME=75 THEN SCAPF=8488. I F NTIME>75 THEN SCAPF=J1L*SCAPF SEE I F DEMAND IS AT THE LEVEL REQUIRING INSTALLATION OF TURBINES ON VANCOUVER ISLAND I F J1L*DTOTF>37000. THEN GO TO 5 I F DTOTF<37000. THEN GO TO 10 STARG31=RTIME+5. START31=RTIME+4. SECNEW=SECNEW+657. SENCAPF=SENCAPF+ (.5*657.) SCAPF=SCAPF+150. 5 I F J1L*DTOTF>41000. THEN GO TO 10 I F DTOTF<41000. THEN GO TO 10 STARG32=RTIME+5. SECNEW=SECNEW+657. SENCAPF=SENCAPF+(.5*657.) SCAPF=SCAPF+150. SET APPROVAL  10  20  30  40  GAS  DATES FOR VARIOUS INCREASINGLY COSTLY ENERGY GENERATION AND ASSOCIATED TRANSMISSION PROJECTS BASED ON COMPARING EXPECTED ENERGY GENERATION CAPACITY (FROM PREVIOUSLY APPROVED PROJECTS) DURING C R I T I C A L RAINFALL PERIODS WITH EXPECTED GROSS ENERGY DEMAND LEVELS, AND ADJUSTING TO INCORPORATE THE DIFFERENT CONSTRUCTION PERIODS REQUIRED. I F NTIME NOT= 78 THEN GO TO 20 STARG12=RTIME+4. SECNEW=SECNEW+875. SENCAPF=SENCAPF+ (.5*875.) I F SENCAPF>=DGROSSF THEN GO TO 500 I F NTIME<=78 THEN GO TO 30 I F STARG14>0. THEN GO TO 30 STARG14=RTIME SECNEl=SECNEW+2750. SENCAPF=SENCAPF+(.5*2750.) I F SENCAPF>=DGROSSF THEN GO TO 500 I F STARG9>0. THEN GO TO 40 STARG9=RTIME START9=RTIME SECNEW=SECNEW+4773. , SENCAPF=SENCAPF+(.5*4773.) SCAPF=SCAPF+900. I F SENCAPF>=DGROSSF THEN GO TO 500 I F STARG10>O. THEN GO TO 50 STARG10=RTIME+1. I F STARG10>(STARG9+2.) THEN STARG10=STARG9+2. START10=STARG10 SECNEW=SECNEW+1634. . SENCAPF=SENCAPF+{.5*1634.)  50  60  70  80  90  130  140  150  160  SCAPF=SCAPF+450. I F SENCAPF>=DGROSSF THEM GO TO 500 I F STARG11>0. THEN GO TO 60 STARG11=RTIME+2. SECNEW=SECNEW+484. I F STARG11>(STARG10+1. ) THEN STARG11=STARG10+1. SENCAPF=SENCAPF+(.5*484.) SCAPF=SCAPF+450. I F SENCAPF>=DGROSSF THEN GO TO 500 I F STARG36>0. THEN GO TO 70 STARG36=BTIME START36=RTIME SECNEW=SECNE8+3420. SENCAPF=SENCAPF+(.5*3420. ) SCAPF=SCAPF+500. I F SENCAPF>=DGROSSF THEN GO TO 500 I F 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. I F SENCAPF>=DGROSSF THEN GO TO 500 I F STARG38>0. THEN GO TO 90 STARG38=HTIME*1. START38= RTIME+1 . SECNEW=SECNE5J*3420. SENCAPF=SENCAPF+ (.5*3420.) SCAPF=SCAPF+500. I F SENCAPF>=DGROSSF THEN GO TO 500 I F STABG39>0. THEN GO TO 130 STARG39=RTIME+1. SECNEw=SECNEH+3420. SENCAPF=SENCAPF+ (. 5*3420.) SCAPF=SCAPF+500. I F SENCAPF>=DGROSSF THEN GO TO 500 I F STABG40>0. THEN GO TO 140 STARG40=RTIME START40=RTIME SECNEB=SECNEw+4790. SENCAPF=SENCAPF+(.5*4790.) SCAPF=SCAPF+700. I F SENCAPF>=DGROSSF THEN GO TO 500 I F 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 I F STARG42>0. THEN GO TO 160 STARG42=RTIME+1. SECNEW=SECNES+4790. SENCAPF=SENCAPF+(.5*4790.) SCAPF=SCAPF+700. I F SENCAPF>=DGROSSF THEN GO TO 500 I F STARG43>0. THEN GO TO 170 STARG43=RTIME+1. SECNEW=SECNEW+4790. SENCAPF=SENCAPF+(.5*4790.) SCAPF=SCAPF+700. I F SENCAPF>=DGROSSF THEN GO TO 500  159  170 I F STARG46>0. THEN GO TO 180 STARG46=RTIME STABT44=RTIME SECNEW=SECNEW+4790. SENGAPF=SENCAPF* (.5*4790.) SCAPF=SCAPF+700. I F SENCAPF>=DGROSSF THEN GO TO 500 180 I F STARG45>0. THEN GO TO 190 STARG45=RTIME START45=RTIME*2. SECNEW=SECNEW*4790. SENCAPF=SENCAPF+ (. 5*4790.) SCAPF=SCAPF+700. I F SENCAPF>=DGROSSF THEN GO TO 500 190 I F 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 I F STABG22>0. THEN GO TO 210 STARG22=RTIME+2. I F 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 I F STARG23>0. THEN GO TO 500 STABG23=BTIME+2. I F STARG23>STARG22 THEN STARG23=STARG22 SECNEW=SECNEW*613. SENCAPF=SENCAPF* (.5*613.) SCAPF=SCAPF+225.  160  RESHARD - DETERHINE DESIBED BESEBVE CAPACITY MABGIN SIX YEARS HENCE BASED ON LGSS-OF-LOAD PROBABILITY METHOD RESULTS FOR EXPECTED NATURE OF GENERATION SYSTEM 500 I F STARG36=0. THEN RESMARDF=.09 I F STARG36>0. THEN RESMABDF=.10 I F STARG37>0. THEN BESMABDF=.11 I F STARG38>0. THEN RESMARDF=.115 I F STARG39>0. THEN BESMABDF=.12 I F S T A R G 4 O 0 . THEN RESMABDF=. 125 I F STARG41>0. THEN RESMARDF=.1325 I F 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-PRODUCING PROJECTS BASED ON COMPARING EXPECTED CAPACITY CAPABILITY FROM PBEVIOOSLY APPBOVED PBOJECTS WITH EXPECTED DESIBED CAPACITY, AND ADJUSTING TO INCOBPOSATE THE VARYING CONSTRUCTION PERIODS. I F SCAPF>=SCAPDF THEN GO TO 1000 I F STARG13>0. THEN GO TO 510 STARG13=RTIME*3.  510  520  530  540  550  560  570  580  1000  SCAPF=SCAPF+275. I F SCAPF>=SCAPDF THEN GO TO 1000 I F STARG16>0. THEN GO TO 520 STARG16=RTIHE+2. SCAPF=SCAPF+4Q0. I F SCAPF>=SCAPDF THEN GO TO 1000 I F STARG17>0. THEN GO TO 530 STARG17=RTIME+2. SCAPF=SCAPF+400. I F SCAPF>=SCAPDF THEN GO TO 1000 I F STARG18>0. THEN GO TO 540 ST ARG18= RTIHE+2. SCAPF=SCAPF+450. I F SCAPF>=SCAPDF THEN GO TO 1000 I F STARG19>0. THEN GO TO 550 ST ABG19=RTIME+2. SCAPF=SCAPF+450. I F SCAPF>=SCAPDF THEN GO TO 1000 I F STARG20>0. THEN GO TO 560 STARG20=RTIME+2. SECNEW=SECNEW+65. SENCAPF=S£NCAPF+(.5*65.) SCAPF=SCAPF+175. I F SCAPF>=SCAPDF THEN GO TO 1000 I F STARG33>0. THEN GO TO 570 ST ARG33=RTIME+5. SECNEW=SECNEB+657. SENCAPF=SENCAPF+(.5*657.) SCAPF=SCAPF+150. I F SCAPF>=SCAPDF THEN GO TO 1000 I F STARG34>0. THEN GO TO 580 STARG34=RTIKE+5. SECNEB=SECNEW+1314. SENGAPF=SENCAPF+{.5*1314.) SCAPF=SCAPF*300. I F SCAPF>=SCAPDF THEN GO TO 1000 I F STARG35>0. THEN GO TO 1000 STARG35=RTIME+5. SECNEW=SECNE»*2628. SENCAPF=SENCAPF+ (.5*2628.) SCAPF=SCAPF+600. SECNEB=SECNEB  161  SUBROUTINE SUPPLY  THIS SECTION TAKES INFORMATION ON DEMAND GROWTH FORECASTS AND DETERMINES THE QUANTITY AND COST OF F A C I L I T I E S THAT SHOULD BE BUILT  ITRS2$76 - INVESTMENT I N NON-ASSOCIATED MAJOR TRANSMISSION PROJECTS I F NTIME=75 THEN ITRS2$76=15. I F NTIME>=76 THEN ITRS2$76=A (2000) * (DPEAK-J1L*DPEAK)  ITRS3$76 - INVESTMENT IN SUE-TRANSMISSION LINES I F NTIME=75 THEN ITRS3$76=10. I F NTIME>=76 THEN ITRS3$76=A (20Q 1) * (DPEAK-J1L*DPEAK)  162  ITRF1$76 - INVESTMENT IN TRANSMISSION TRANSFORMATION I F NTIHE=75 THEN ITRF1$76=5. I F 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. I F NTIME>=76 THEN ITRF2$76=A(2003)*(DPEAK-J1L*DPEAK) IDST1$76 - INVESTMENT IN DISTRIBUTION F A C I L I T I E S FOR NEB CUSTOMERS I F NTIME=75 THEN IDST1$76=50. IF NTIME>=76 THEN IDST1$76=A(2004)*(NOCUST-J1L*NOCUST) IDST2$76 - INVESTMENT IN DISTRIBUTION F A C I L I T I E S FOR GROWTH BY EXISTING CUSTOMERS I F NTIME=75 THEN IDST2$76=10. , I F NTIME>=76 THEN IDST2$76=A (2005) * (DPEAK-J1L*DPEAK) IMISCS76 - INVESTMENT IN OTHER ELECTRIC PLANT I F NTIME=75 THEN IMISC$76=6. I F NTIME>=76 THEN IMISC$7 6= A (2006)*(DTOT—J1L*DT0T) SET IF IF IF IF IF IF IF  ANY NEGATIVE ITRS2$76<0. ITSS3$76<0. ITRF1$76<0. ITRF2$76<0. IDST1$76<0. IDST2$76<0. IMISC$76<0.  INVESTMENT TO ZERO THEN ITRS2$76=0. THEN ITRS3$76=0. THEN ITRF1$76=0. THEN ITRF2$76=0. THEN IDST1$76=0. THEN IDST2$76=0. THEN IMISC$76=0.  ITRS$74 - INVESTMENT IN MAJOR TRANSMISSION PROJECTS  AND  SUB-TRANSMISSION  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 PLANT IN SERVICE {$76) KPST2$76=J1L*KPST2$76+ITRS2$76+ITRS3$7 6  SUB-TRANSMISSION  KPSTF$76 - NEW TRANSFORMATION PLANT IN SERVICE ($76) KPSTF$76=J1L*KPSTF$76+ITRF1$76+ITSF2$76 KEIST$76 - ALL NEW TRANSMISSION AND TRANSFORMATION IN SERVICE ($76)  PLANT  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 IN SERVICE ($76) KPST4$76=J1L*KPST4$76+ITRF2$76 KPISD$76 - NEW  PLANT  DISTRIBUTION PLANT IN SERVICE ($76)  KPISB$76=J1L*KPISD$76+IDST1$76+IDST2$76+IMISC$76 KPISM$76 - NEW MISCELLANEOUS PLANT I N SERVICE LEVEL CUSTOMERS  ($76) FOR 230 KV  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 SUBTRANSMISSION 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.  IF  SCAPH>=6400. THEN RESMARD=.09  IF  SCAPOO.  IF  SCAPC>=500. THEN  IF  SCAPC>=1000. THEN  BESMABD=.11  IF  SCAPC>=1500. THEN  RESMARD=.115  IF  SCAPC>=2000. THEN BESMABD=.12  IF  SCAPC>=2500. THEN  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  THEN RESMARD=.095  THEN RESMARD=. 10 RESMARD=.105  BESMARD=.125  SCAPD - DESIRED CAPACITY CAPABILITY CAPACITY MARGIN)  (INCLUDES DESIRED RESERVE  SCAPD=DPEAK*(1. +RESMARD) SCAP - ANNUAL  CAPACITY CAPABILITY  SCAP=SCAPH*SCAPB+SCAPC+SCAPK+SCAPG SCAPSURP - SURPLUS (DEFICIT) OF ACTUAL CAPACITY CAPABILITY DESIRED CAPACITY CAPABILITY SCAPSURP=SCAP-SCAPD RESMAB  - ACTUAL RESERVE CAPACITY MARGIN  RESMAR=(SCAP-DPEAK) /DPEAK DETERMINE ACTUAL ENERGY PRODUCED FROM  SENERH - ACTUAL ENERGY SENEBH=DGBOSS  EACH SOURCE  PRODUCED FROM HYDRO SOURCES  OVER  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 SENERHC—SENERCC  IF  DGROSS>(SENERHC+SENERCC + SENERKC) THEN SENERK=SENERKC  SENERB - ACTUAL ENERGY PRODUCED  SENERK=DGROSS-  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. I F 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 U T I L I T I E S B C HYDRO SEEKS TO EXPORT ELECTRICITY WHEN GROSS DOMESTIC DEMAND I S LESS THAN ENERGY GENERATION CAPACITY AND VARIABLE OPERATING COSTS ARE B E L O l EXPORT PRICES. THE EXTENT TO WHICH IT FINDS A MARKET FOR ANY ECONOMICALLY SURPLUS POWER I S DETERMINED BY THE FRACTION SET BY A (1873) I F A (1863) >=A (1879) THEN GO TO 100  DEXPORT=A(1873)*(SENERHC*SENERCC*SENERKC—DGROSS) IF  DEXPORT<0. THEN  DEXPORT=0.  I F 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.  I F 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 I F DIFFH>0. THEN GO TO 30 I F D I F F O O . THEN GO TO 40 SENERK=SENERK*DEXPORT GO TO 200 30 SENERH=SENERH+DEXPORT I F SENERH>SENERHC GO TO 200 40  THEN GO TO 50  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)  166  IF  DEXPORT<0.  THEN  DEXPORT=0.  IF  DEXPGRT=G.  THEN GO TO 200  167  I F A (1862) <A (1879) THEN GO TO 110 DEXPORT=SEN EBHC-DGBOSS IF  DEXPORT<0. THEN  DEXPOBT=0.  I F DEXPORT=0. THEN GO TO 200 SENEBH=SENEBH+DEXPOET GO TO 200 110 DIFFH=SENERHC-SENERH I F 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 200  GENERATED  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.  I N I T I A L I Z E 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 SEHCC=0. VARIOUS CATEGORIES OF AVERAGE ENERGY CAPABILITY SEHAC=0. SECAC=0. SEKAC=0. SEGAC=0. VARIOUS CATEGORIES OF GENERATION SCH=0. SCC=0. SCK=0. SCG=0. CAPITAL EXPENDITURES 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.  CAPACITY CAPABILITY  ($76) FOR EACH GENERATION  PROJECT  PERIODS  G43$76=0. G44$76=0. G45$76=0. G46$76=0. G47$76=0. G48$76=0. G49$76=0. G50$76=0. CAPITAL EXPENDITURES 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.  169  ($76) FOR EACH MAJOR ASSOCIATED TRANSMISSION  GO TO APPROPRIATE PROJECTS I F COEFFICIENTS INDICATE AN ECONOMIC ANALYSIS OF PROJECT I S DESIRED I F A j(2011) =0. THEN GO TO 5 I F A (2011) = 1. THEN GO TO 90 IF A (2011) =2. THEN GO TO 120 I F A (2011) = 3. THEN GO TO 130 I F A (2011) =4. THEN GO TO 140 I F A (2011) =5. THEN GO TO 160 I F A (2011) = 6. THEN GO TO 80 I F A (2011) = 7. THEN GO TO 210 I F A j(2011) = 8. THEN GO TO 60 I F A (2011) -11 . THEN GO TO 310 I F A (2011] = 16 . THEN GO TO 360 I F A (2011) = 17 . THEN GO TO 400 I F A (2011] =21 . THEN GO TO 440 5 I F A (2010) = 0. THEN GO TO 10 I F A (2010) = 6. THEN GO TO 60 I F A (2010) =7. THEN GO TO 70 I F A (2010) = 8. THEN GO TO 80 I F A (2010) = 9. THEN GO TO 90 I F A (2010) = 10 . THEN GO TO 100 I F A (2010] = 11 . THEN GO TO 1 10 I F A (2010) = 12 . THEN GO TO 120 I F A (2010) = 13 . THEN GO TO 130 I F A (2010) = 14. THEN GO TO 140 IF A (2010) = 16 . THEN GO TO 160 IF A (2010) = 17 . THEN GO TO 170 I F A (2010) = 18 . THEN GO TO 180 I F A (2010) = 19 . THEN GO TO 190 I F A (2010) = 20 . THEN GO TO 200 IF A (2010) =21 . THEN GO TO 210 I F A (2010] = 22 . THEN GO TO 220 I F A (2010) = 23 . THEN GO TO 230  I F A(2010) = 31. THEN I F A (2010) = 32. THEN I F A(201G) = 36. THEN I F A (2010) = 37. THEN I F A (2010) = 38. THEN I F A (2010) = 39. THEN I F A (2010) = 40. , THEN I F A(2010) = 41. THEN I F A(2010) =42. THEN I F A (2010) = 43. THEN I F A (2010) =44. THEN I F A<2010) =45. THEN  GO GO GO GO GO GO GO GO GO GO GO GO  TO TO TO TO TO TO TO TO TG TO TO TO  310 320 360 370 380 390 400 410 420 430 440 450  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 I F RTIME>STARG1 THEN GO TO 20 I F RTIME=STARG1 THEN G1$76=13.1*A(1901) IGl$=PEXOG/2.11*G1$76 IDCG1$=6. IDC$=IDC$+IDCG1$ 20 I F RTIME>STARG2 THEN GO TO 30 I F RTIME<STAEG2 THEN GO TO 30 I F RTIME-STARG2 THEN G2$76=4. 8*A (1 902) IG2$=PEXOG/2.11*G2$76 IDCG2$=2. IDC$=IDC$+IDCG2$ I F 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 I F RTIME>(STARG3+1.) THEN GO TO 40 I F RTIME=STARG3 THEN G3$76=60.5*A(1903) I F RTIME= (STAEG3 + 1. ) THEN G3$76=41. 5*A (1 903) IG3$=PEXOG/2.11*G3$76 I F RTIME=STARG3 THEN IDCG3$=13. I F RTIME= (STARG3 + 1.), THEN IDCG3$=18. IDC$=IDC$+IDCG3$ I F 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 I F RTIME>STARG4 THEN GO TO 50 I F RTIME=STARG4 THEN G4$76=13.6*A(1904) IG4$=PEXOG/2.11*G4$76 I F RTIME=(STARG4-1.) THEN IDCG4$=3. I F RTIME=STAEG4 THEN IDCG4$=6.5 I F RTIME=(STARG4*1.) THEN IDCG4$=14. IDC$=IDC$+IDCG4$ I F 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.  50  I F  RTIME>STARG5  THEN  I F  RTIME=STARG5  THEN  GO  TG  60  171  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  RTIME=(STARG5-3.)  THEN  I F  RTIME=(STARG5-2.)  THEN  IDCG5$=3.  I F  RTIME=(STARG5-1.)  THEN  I D C G 5 $ = 6 .  I F  RTIME=STARG5  THEN  I D C G 5 $ = 1 .  I D C G 5 $ = 1 2 .  IDC$=IDC$+IDCG5$ I F  RTIME  NOT=  PH$76=PH$76+  STARG5  ( 1 0 0 .*A  THEN  GO  TO  60  GO  TO  68  ( 1 9 0 5 ) )  PH$H=PH$H+179. SEHCC=SEHCC+700. SEHAC=SEHAC+810. SCH=SCH+0. 60  I F  RTIME>(STARG6+4.)  I F  RTIME= STARG6  THEN  THEN  G 6 $ 7 6 = 2 1 . 6 * A ( 1 9 0 6 )  I F  RTIME=(STABG6+1.)  THEN  G 6 $ 7 6 = 4 6 . 9 * A  {1906)  I F  RTIME=(STARG6+2.)  THEN  G 6 $ 7 6 = 5 3 . 4 * A  (1906)  I F  RTIME= (STARG6+3.)  THEN  G 6 $ 7 6 = 4 2 . 4*A {1906)  I F  RTIME=(STARG6+4.)  THEN  G 6 $ 7 6 = 2 0 . 9*A (1906)  I G 6 $ = P E X O G / 2 . 1 1 * G 6 $ 7 6 IDCG6$=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 $ ) IDC$=IDC$+IDCG6$ I F  RTIHE  NOT=  (STARG6+4.)  THEN  GO  TO  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+1941. SEHAC=SEHAC+1881. SCH=SCH*525. 68 70  ,  I F  A (2011)  NOT=  0 .  THEN  GO  TO  70  I F  A (2010)  NOT=  0.  THEN  GO  TO  5 0 5  I F  RTIHE> (STARG7+4.)  THEN  I F  RTIME=STARG7  G7$76=1 . * A  THEN  GO T O  78 (1907)  I F  RTIME=(STARG7+1.)  THEN  I F  RTIME=(STARG7+2.)  THEN  G7$76=  1 . 6 * A { 1 9 0 7 )  I F  RTIME=(STARG7+3.)  THEN  G 7 $ 7 6 = 4 . 3 * A { 1 9 0 7 )  I F  RTIME=(STARG7+4.)  THEN  G7$76=5. 9 * A { 1907)  G 7 $ 7 6 = 2 . 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  RTIME  NOT=  (STARG7+4.)  THEN  GO TO  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 $ SEHCC=SEHCC+1412. SEHAC=SEHAC*136  9.  SCH=SCH+175. 78 80  I F  A (2011)  NOT=  0 .  THEN  GO  TO  5 0 5  I F  A ( 2 0 1 0 )  NOT=  0 .  THEN  GO T O  5 0 5  I F  RTIME>(STARG8+5.)  THEN  I F  RTIME=STARG8  G 8 $ 7 6 = 9 . 7 * A  I F  RTIME=(STARG8+1.)  THEN  G8$76=17.4*A  I F  RTIME=(STARG8+2.)  THEN  G 8 $ 7 6 = 3 7 . 5 * A (19 0 8 )  I F  RTIME=  (STARG 8 + 3 . )  THEN  G 8 $ 7 6 = 5 1 . 9*A (1908)  I F  RTIME= (STARG8+4.)  THEN  G 8 $ 7 6 = 4 1 . 6 * A (19 0 8 )  THEN  GO  TO  88 (1908) (1908)  I F 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$+IDCG8$ I F 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 I F THIS PROJECT I S BEING COSTED 88 I F A{2011) NOT= 0. THEN GO TO 200 SEE I F THIS UNIT I S BEING COSTED I F A (2010) NOT= 0. THEN GO TO 505 SEE I F THIS PROJECT HAS ALREADY BEEN COMPLETED 90 I F RTIME>{STARG9-»-6.) THEN GO TO 98 DETERMINE REAL CONSTRUCTION EXPENDITURES IN THE CURRENT YEAR I F RTIME=STARG9 THEN G9$76=5. 1 *A (1 909) I F RTIME=(STARG9 + 1.) THEN G9$76= 32.7*A (1909) I F RTIME=(STARG9 + 2.) THEN G9$76=37.9*A (1909) I F RTIME= {STARG9 + 3.) THEN G9$76=73.6*A (1 909) I F RTIME=(STARG9+4.) THEN G9$76=132.1*A{1909) I F RTIME=(STARG9+5.) THEN G9$76=152.3*A{1909) I F RTIME=(STARG9 + 6.) THEN G9$76=23.*A (1909) DETERMINE NOMINAL CONSTRUCTION IG9$=PEXOG/2.11*G9$76  EXPENDITURES IN THE CURRENT YEAR  CALCULATE INTEREST DURING CONSTRUCTION FOR THIS PROJECT IDCG9$=A (1872) * { (.5*IG9$) *J1L*IG9$*J2L*IG9$+ J3L*IG9$+J4L*IG9$+J5L*IG9$+J6L*IG9$) CALCULATE ALL INTEREST DURING CONSTRUCTION IDC$=IDC$+IDCG9$ IF RTIME NOT=  FOR THE CURRENT YEAR  (STARG9+6.) THEN GO TO 98  HERE I F PROJECT I S COMPLETED THIS YEAR AUGMENT REAL PLANT IN SERVICE FOR THIS CATEGORY PH$76=PH$76+(456.7*A (1909))  (HYDRO)  AUGMENT HISTORIC DOLLAR PLANT IN SERVICE FOR THIS CATEGORY (HYDRO) PH$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 SEHCC=SEHCC+4773. . AUGMENT AVERAGE ENERGY SEHAC=SEHAC+5520.  CAPABILITY FOR THIS CATEGORY  AUGMENT CAPACITY CAPABILITY FOR THIS CATEGORY  (HYDRO) (HYDRO)  (HYDRO)  SCH=SCH+900. 173 98 I F A(2011) NOT= 0. THEN GO TO 100 I F ft (2010) NOT= 0. THEN GO TO 505 100 I F RTIME>{STARG10*6.) THEN GO TO 108 I F RTIM E= ST A RG10 THEN G10$76=. 1*A{1910) I F RTIME=(STARG10+1.) THEN G10$76=1.9*A{1910) I F RTIME=(STARG10+2.) THEN G10$76=2. 9*A (1 9 10) I F RTIME=(STARG10+3.) THEN G10$76=4.8*A{1910) IF RTIME=(STARG10+4.) THEN G10$76=7.9*A{1910) I F RTIME=(STARG10+5. ) THEN G10$76=4. 5*A (1 910) I F 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 I F A{2011) NOT= 0. THEN GO TO 110 I F A (2010) NOT= 0. THEN GO TO 505 110 I F RTIME>(STARG11*4.) THEN GO TO 118 I F RTIME=STARG1 1 THEN G 11 $76= 1. 9*A { 191 1) I F RTIME=(STARG11+1.) THEN G11$76=2.9*A{1911) I F RTIME=(STARG11+2.) THEN G11$76=4.8*A (1911) I F RTIME= (STARG 11+3.) THEN G11 $7 6=7. 9*A { 19 11) I F 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$+IDCG11$ I F 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 I F A{2011) NOT= 0. THEN GO TO 180 I F A{2010) NOT= 0. THEN GO TO 505 120 I F RTIME<STARG12 THEN GO TO 128 I F RTIME>(STARG12+2.) THEN GO TO 128 I F RTIME=STARG12 THEN G12$76=2.*A{1912) I F RTIME= (STARG 12 + 1.) THEN G 12$7 6=5. *A (1 9 12) I F 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$+IDCG12$ I F 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.  128 130  138 140  150 158 160  SEHAC=SEHAC+875. 174 SCH=SCH+0. I F A (2011) NOT= 0. THEN GO TO 505 IF A(2010) NOT= 0. THEN GO TO 505 I F RTIHE<STAEG13 THEN GO TO 138 I F RTIME>(STARG13+3.) THEN GO TO 138 I F RTIME=STARG13 THEN G13$76=2.4*A{1913) I F RTIME=(STARG13+1.) THEN Gl3$76=5.3*A(19 13) I F RTIME=(STARG13+2.) THEN G13$76=6.*A (1913) I F 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$+IDCG13$ I F 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. I F A(2011) NOT= 0. THEN GO TO 505 I F A (2010) NOT= 0. THEN GO TO 505 I F RTIME<STARG14 THEN GO TO 158 I F RTIME> (STARG 14+6.) THEN GO TO 158 I F RTIME=STARG14 THEN G14$76=1.9*A (1914) I F RTIME=(STARG14 + 1.) THEN G14$76=12.8*A {1914) I F RTIME= (STARG 14+2. ) THEN G 14$7 6=33. 8*A (1914) I F RTIME=(STARGl4+3.) THEN G14$76=42.5*A (1914) I F RTIME= (STARG 14 + 4.) THEN G1 4$76= 28. 4*A { 1 91 4) I F RTIME=(STARG14+5.) THEN G14 $76= 11. 9*A ( 19 1 4) I F RTIME=(STARG14+6.) THEN G14$76=2.1 *A{1914) IGl4$=PEX0G/2.11*G14$76 IDCG14$=A(1872) * ( (.5*IG14$) • J 1 L * I G 1 4 $ + J 2 L * I G 1 4 $ * J3L*IG14$+J4L*IG14$+J5L*IG14$+J6L*IG14$) IDC$=IDC$+IDCG14$ I F 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$ I F STARG21<=STAEG14 THEN GO TO 150 SEHCC=SEHCC+2750. SEHAC=SEHAC+3110. SCH=SCH+0. GO TO 158 SEHCC=SEHCC+3346. SEHAC=SEHAC+382 8. SCH=SCH+0. I F A(2011) NOT= 0. THEN GO TO 505 I F A(2010) NOT= 0. THEN GO TO 505 I F RTIME<STARG16 THEN GO TO 168 I F RTIME>(STARG16+4.) THEN GO TO 168 I F RTIME=STARG16 THEN G16$76=1,*A{1916) I F RTIME=(STARG16 + 1.) THEN G16$76=2 . * A (1916) I F RTIME= (STARG 16 + 2.) THEN G16$7 6=3. *A (191 6) I F RTIME=(STARG16 + 3.) THEN G16$76=7.*A (1916) I F RTIME=(STARG16+4.) THEN G16$76=3,*A{1916) IG16$=PEXOG/2.11*G16$76  168 170  178 180  188 190  IDCG16$=A(1872) * ( ( . 5 * I G 1 6 $ ) + J 1 L * I G 1 6 $ + J2L*IG16$+ 175 J3L*IG16$+J4L*IG16$+J5L*IG16$+J6L*IG16$) IDC$=IDC$*IDCG16$ I F 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. I F A(2011) NGT= 0. THEN GO TO 170 IF A (2010) NOT= 0. THEN GO TO 505 I F RTIME<STARG17 THEN GO TO 178 I F RTIME>(STARG17*4.) THEN GO TO 178 I F RTIME=STARG17 THEN G17$76=1.*A(1917) I F RTIME=(STARG17+1.) THEN G 17$76=2. *A {1917) I F RTIME=(STARG 17 + 2.) THEN G 17$76=3 . * A (1 917) I F RTIME=(STARG17+3. ) THEN G17$76=6.3*A(1917) I F 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$+IDCG17$ I F 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. I F A (2011) NOT= 0. THEN GO TO 505 IF A(2010) NOT= 0. THEN GO TO 505 I F RTIME<STARG18 THEN GO TO 188 I F RTIME>(STARG18+4.) THEN GO TO 188 I F RTIME=STARG18 THEN G18$76=2.*A{1918) I F RTIME=(STARG18+1.) THEN G18$76=3.*A(1918) I F RTIME=(STARGl8+2. ) THEN G18$76=5.*A (1918) I F RTIME=(STARG18+3.) THEN G1 8$7 6= 8. *A { 1 91 8) I F 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$+IDCG18$ I F 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. I F A (2011) NOT= 0. THEN GO TO 190 I F A (2010) NOT= 0. THEN'GO TO 505 I F RTIME<STARG19 THEN GO TO 198 IF RTIHE>(STARG19+4.) THEN GO TO 198 I F RTIME=STARG19 THEN G19$76=2.*A(1919) I F RTIME=(STARG19+1.) THEN G19$76=3.*A{1919) I F RTIME=(STARGl9+2.) THEN G19$76=5.*A (1919)  198 200  208 210  218  I F RTIME= {STARG19 +3.) THEN G19$76=8. *A (191 9) 176 I F 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$+IDCG19$ I F 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. I F A{2011) NOT= 0. THEN GO TO 505 I F A(2010) NGT= 0. THEN GO TO 505 I F RTIME<STARG20 THEN GO TO 208 I F RTIME>{STARG20+4.) THEN GO TO 208 I F RTIME=STARG20 THEN G20$76=.7*A{1920) I F RTIME= (STARG20 + 1. ) THEN G20$76=1.1*A(1920) I F RTIME=(STARG20+2.) THEN G20$76=1.7*A{1920) I F RTIME=(STARG20+3.) THEN G20$76=5.4*A (1920) I F 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$+IDCG20$ I F 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. I F A (2011) NOT= 0. THEN GO TO 505 I F A (2010) NOT= 0. THEN GO TO 505 I F STARG21=0. THEN GO TO 238 I F RTIME>(STARG21+6.) THEN GO TO 218 I F RTIME=STARG21 THEN G21$76=3.*A{1921) I F RTIME=(STARG21 + 1.) THEN G21$76=24.*A (1921) I F RTIME= {STARG21 + 2. ) THEN G21 $76=28. 5*A {1 92 1) I F RTIME={STARG21+3.) THEN G21$76=54.*A{1921) I F RTIME={STARG21+4.) THEN G21$76=98.*A{ 1921) I F RTIME=(STARG21+5.) THEN G21$76=111.*A(1921) I F 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$+IDCG21$ I F 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. I F A {2011) NOT= 0. THEN GO TO 220 IF A (2010) NOT= 0. THEN GO TO 505  220 I F RTIME>(STARG22+4.) THEN GO TO 228 177 I F RTIME=STARG22 THEN G22$76=1.*A{1922) I F RTIME=(STARG22+1.) THEN G22$76= 1.6*A (1922) I F RTIHE= (STARG22+2.) THEN G22$76=2.9*A (1922) I F RTIME=(STARG22+3.) THEN G22$76=4.3*A(1922) I F 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$+IDCG22$ I F 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 I F A(2010) NOT= 0. THEN GO TO 505 230 I F RTIHE>{STARG23*4.) THEN GO TO 238 I F RTIME=STARG23 THEN G23$76 = 1.*A (1923) I F RTIME=(STARG23*1.) THEN G23$76=1.6*A (1923) I F RTIME=(STARG23+2.) THEN G23$76=2.9*A{1923) I F RTIME=(STARG23+3.) THEN G23$76=4.3*A(1923) I F 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$ + J 3 L * I G 2 3$*J4L*IG23$*J5L*IG23$+J6L*IG23$) IDC$=IDC$+IDCG23$ I F 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 I F A (2011) NOT= 0. THEN GO TO 505 I F A (2010) NOT= 0. THEN GO TO 505 240 I F STARG24=0. THEN GO TO 310 310 I F RTIME<STARG31 THEN GO TO 318 I F RTIME>(STARG31+1.) THEN GO TO 318 I F RTIME=STARG31 THEN G31$76=11.6*A(1931) I F 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$ I F 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 I F A{2011) NOT= 0. THEN GO TO 320 I F A (2010) NOT= 0. THEN GO TO 505 320 I F RTIME<STARG32 THEN GO TO 328 I F RTIME>(STARG32+1.) THEN GO TO 328 I F RTIME=STARG32 THEN G32$76=11.6*A{1932) I F RTIME=(STARG32+1.) THEN G32$76=10.*A{1932) IG32$=PEXOG/2.11*G32$76  328 33 0  338 340  348 350  358 360  IDCG32$=A (1872) * ( (. 5*IG3 2$) +J 1L*IG32$) IDC$=IDC$*IDCG32$ I F 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. I F A (2011) NOT= 0. THEN GO TO 505 I F A (2010) NOT= 0. THEN GO TO 505 I F RTIHE<STARG33 THEN GO TO 338 I F RTIME>{STARG33*1.) THEN GO TO 338 I F RTIME=STARG33 THEN G33$76= 11. 6*A{1933) I F 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$ I F 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. I F A (2011) NOT= 0. THEN GO TO 505 I F A (2010) NOT= 0. THEN GO TO 505 I F RTIME<STARG34 THEN GO TO 348 I F RTIME>(STARG34+1.) THEN GO TO 348 I F RTIME=STARG34 THEN G34$76=23. 2*A{1934) I F 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$ I F 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. I F A (2011) NOT= 0. THEN GO TO 505 I F A(2010) NOT= 0. THEN GO TO 505 I F RTIME<STARG35 THEN GO TO 358 I F RTIME>(STARG35+1.) THEN GO TO 358 I F 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$ I F 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. I F A (2011) NOT= 0. THEN GO TO 505 IF A (2010) NOT= 0. THEN GO TO 505 I F RTIME>(STARG36+6.) THEN GO TO 368 I F RTIME<STARG36 THEN GO TO 505 I F RTIME=STARG36 THEN G36$76=1.*A{1936) I F RTIME=(STARG36+1.) THEN G36$76=5.*A (1936) I F RTIME=(STARG36 + 2.) THEN G36$76=20.* A(1936) I F RTIME=(STARG36+3.) THEN G36$76=40.*A{1936} I F RTIME=(STARG36 + 4.), THEN G36$76=50. *A (1936) I F RTIME=(STARG36+5.) THEN G36$76=59.*A(1936) I F RTIME=(STARG36+6.) THEN G36$76=25.*A{1936)  368 370  378 380  388 390  IG36$=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$+IDCG36$ I F 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. I F A (2011) NOT= 0. THEN GO TO 370 I F A(2010) NOT= 0. THEN GO TO 505 I F BTIME>(STARG37+5.) THEN GO TO 378 I F RTIS3E=STARG37 THEN G37$76=2.*A (1937) I F RTIHE=(STARG37+1.) THEN G37$76=13.*A(1937) I F BTIHE=(STARG37+2.) THEN G37$76=25.*A{1937) I F RTIME=(STARG37+3.) THEN G37$76=25.*A (1937) I F RTIME=(STARG37+4.) THEN 637$76=30.*A{1937) I F 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$+IDCG37$ I F 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. I F A (2011) NOT= 0. THEN GO TO 380 IF A(2010) NOT= 0. THEN GO TO 505 I F BTI!9E> (STAR038+5. ) THEN GO TO 388 I F R TIME=ST A RG 3 8 THEN G38$76=2.*A (1938) I F RTIHE=(STARG38+1.) THEN G38$76=13.*A(1938) IF RTIHE=(STARG38+2.) THEN 638$76=25.*A{1938) I F RTIHE=(STAR638+3.) THEN 638$76=25.* A(1938) I F BTIME= (STARG38+4.) THEN G38$76=30.* A{1938} I F 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$+ J 4 L * I G 3 8$+J51*IG38$+J6L*IG38$+IDCG38$+J1L*IDCG38$+ J2L*IDCG38$+J3L*IDCG38$+J4L*IDCG38$+J5I*IDCG38$+J6L*IDCG38$ SECAC=SECAC+3420. SCC=SCC+500. I F A (2011) NOT= 0. THEN GO TO 390 I F A(2010) NOT= 0. THEN GO TO 505 I F BTIME>(STABG39+5.) THEN GO TO 398 I F RTIME=STARG39 THEN G39$76=2.*A(1939) I F RTIHE=(STARG39+1.} THEN G39$76=13.*A(1939) I F RTIME=(STARG39+2.) THEN 639$76=25.*A{1939) I F RTIME=(STARG39+3.) THEN G39$76=25.*A (1939) I F RTIME=(STABG39+4.) THIN G39$76=30.*A{1939) I F RTIHE=(STARG39+5.)THEN G39$76=11.*A{1939)  398 400  408 410  418 420  IG39$=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$+IDCG39$ I F 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$+ J 4 L * I G 3 9$+J5L*IG39$+J6L*IG39$*IDCG39$*J1L*IDCG39$+ J2L*IDCG39$+J3L*IDCG39$+J4L*IDCG39$+J5L*IDCG39$+J6L*IDCG39$ SECAC=SECAC*3420. SCC=SCC+500. I F A{2011) NOT= 0. THEN GO TO 505 I F A(2010) NOT= 0. THEN GO TO 505 I F RTIME>(STARG40+6.) THEN GO TO 408 I F RTIME=STARG40 THEN G 4 0$76=5.*A(1940) I F RTIME=(STARG40+1.) THEN G40$76=15.*A (1940) I F RTIME= (STARG40+2.) THEN G40$76=30.*A(1940} I F RTIME= (STARG40+3.) THEN G40$76=40.*A (1940) I F RTIME=(STARG40+4.) THEN G40$76=45.* A(19 40} I F RTIME= (STARG40+5.) THEN G40$76=50.*A{1940) I F 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$+IDCG4 0$ I F 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. I F A(2011) NOT= 0. THEN GO TO 410 I F A (2010) NGT= 0. THEN GO TO 505 I F RTIME>(STARG41+5.) THEN GO TO 418 I F RTIME=STARG41 THEN G41$76=7.*A{1941) I F RTIME= (STARG41*1.) THEN G41$76=20.*A(1941) I F RTIME=(STARG41+2.) THEN G41$76=30.*A (1941) I F RTIME= (STAEG41 + 3.) THEN G41$76=35.*A(1941) I F RTIME=(STARG41 + 4.) THEN G41$76=50.*A (1941) I F RTIME=(STAEG41 + 5.) THEN G41$76=15.*A {1941) IG41$=PEXOG/2.11*G41$76 IDCG41$=A ( 1 8 7 2 ) * ( (.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. I F A(2011) NOT= 0. THEN GO TO 420 I F A{2010) NOT= 0. THEN GO TO 505 I F RTIME>(STARG42+5.) THEN GO TO 428 I F RTIME=STARG42 THEN G42$76=7.*A{1942) I F RTIME=(STARG42*1.) THEN G42$76=20.*A{1942) I F RTIME=(STARG42+2.) THEN G42$76=30.*A (1942) I F RTIHE=(STARG42+3.) THEN G42$76=35.*A{1942) I F RTIME=(STARG42+4.) THEN G42$76=50.*A(1942)  428 430  438 440  448 450  I F RTIME={STARG42+5.) THEN G42$76=15.*A (1942) 181 IG42$=PEX0G/2.11*G42$76 IDCG42$=A ( 1 8 7 2 ) * ( (-5*IG42$)+J1L*IG42$+J2L*IG42$+ J3L*IG42$+J4L*IG4 2$+J5L*IG42$+J6L*IG42$) IDC$=IDC$+IDCG42$ I F 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$+J6I,*IDCG42$ S E C A O S E C A C + 4790. SCC=SCC+700. I F A{2011) NOT= 0. THEN GO TO 430 I F A (2010) NOT= 0. THEN GO TO 505 I F RTIME>(STAEG43+5.) THEN GO TO 438 I F RTIME=STARG43 THEN G43$76=7.*A(1943) I F RTIME=(STARG43+1.) THEN G43$76=20.*A(1943) I F RTIME=(STARG43+2.) THEN G43$76=30.*A (1943) I F RTIME={STARG43 + 3.) THEN G43$76=35.*A {1943) I F RTIME=(STAEG43+4.) THEN G43$76=50.*A{1943) I F 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$+IDCG43$ I F 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. I F A(2011) NOT= 0. THEN GO TO 505 I F A (2010) NOT= 0. THEN GO TO 505 I F RTIME<STARG46 THEN GO TO 460 I F RTIME>(STARG46+6.) THEN GO TO 448 IF RTIME=STARG46 THEN G44$76=3.*A{1944) I F RTIME=(STARG46 + 1.) THEN G44$76=8. *A (1944) I F RTIME= (STARG46 + 2.) THEN G 44$76= 19 . * A { 19 44) I F RTIME=(STARG46+3.) THEN G44$76=35.*A(1944) I F RTIME=(STARG46+4.) THEN G44$76=45.*A{1944) IF RTIME=(STARG46+5.) THEN G44$76=45.*A(1944) I F 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. I F A(2011) NOT= 0. THEN GO TO 450 I F A{2010) NOT= 0. THEN GO TO 505 I F HTIME<STARG45 THEN GO TO 458 I F RTIME>(STARG45+6.) THEN GO TO 458 I F RTIME=STARG45 THEN G45$76=2.*A {1945) I F RTIME= (STARG45 + 1. ) THEN G45$76=5.*A (1 945)  458 460  468 470  I F RTIME=(STARG45+2.) THEM G45$76= 10.*A{1945) 182 I F RTIME=(STARG45*3.) THEN G45$76=15.*A(1945) I F RTIME=(STARG45+4.) THEN G45$76=25.*A (1945) IF RTIME=(STARG45 + 5.) THEN G45$76=30.*A{1945) I F 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$* J 3 L * I G 4 5$+J4L*IG45$+J5L*IG45$+J6L*IG45$) IDC$=IDC$+IDCG45$ I F 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. I F A (2011) NOT= 0. THEN GO TO 505 I F A (2010) NOT= 0. THEN GO TO 505 I F RTIME<STARG46 THEN GO TO 468 I F RTIME>(STARG46+6.) THEN GO TO 468 I F RTIME=STARG46 THEN G46$76=2.*A{1946) I F RTIME=(STARG46+1.) THEN G46$76=5 . *A (1 946) I F RTIME=(STARG46+2.) THEN G46$76=10.*A{1946) I F RTIME=(STARG46+3.) THEN G46$76=15.* A(1946) I F RTIME=(STARG46+4.) THEN G46$76=25.*A{1946) I F RTIME=(STARG46*5.) THEN G46$76=30.*A{1946) I F RTIME=(STARG46+6.) THEN G46$76=40.*A (1946) IG46$=PEXOG/2.11*G46$76 IDCG46$=A (1872) *{{.5*IG46$) * J 1 L * I G 4 6 $ + J 2 L * I G 4 6 $ • J3L*IG46$*-J4L*IG46$+J5L*IG46$+J6L*IG46$) IDC$=IDC$+IDCG46$ I F 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. I F - A (2011) NOT= 0. THEN GO TO 505 I F A (2010) NOT= 0. THEN GO TO 505 I F STARG47=0. THEN GO TO 505  THE FOLLOWING SECTION AGGREGATES THE KEY FINANCIAL AND ENGINEERING VARIABLES FOR ALL THE GENERATION PROJECTS IGEN$76 - INVESTMENT I N 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 I N 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 I F RTIME=75. THEN SENHCC1=19903. I F RTIME>=76. THEN SENHCC1=J1L*SENHCC1+SEHCC  SENERHCC - AVERAGE ENERGY GENERATION CAPACITY FROM HYDRO SOURCES DURING C R I T I C A L RAINFALL PERIOD I F RTIME=75. THEN S ENERHCC=19903. I F RTIME>=76. THEN SENERHCC=J1L*SENHCC1*{.5*SEHCC)  183  SENHAC1 - ENERGY GENERATION CAPACITY FROM HYDRO-ELECTRIC SOURCES DURING AVERAGE RAINFALL PERIOD AT END OF EACH YEAR I F RTIME=75. THEN SENHAC1=21800. I F RTIME>=76. THEN SENHAC1=J1L*SENHAC1+SEHAC SENERHAC - AVERAGE ENERGY GENERATION CAPACITY FROM HYRDOELECTRIC SOURCES DURING AVERAGE RAINFALL PERIOD IF RTIME=75. THEN SENERHAC=21800. I F RTIME>=76. THEN SENERHAC=J1L*SENHAC1•(.5*SEHAC) SENGAC1 — ENERGY GENERATION CAPACITY FROM GAS TURBINES AT YEAR END I F RTIME=75. THEN J1L*SENGAC1=1476. I F RTIME>=75. THEN SENGAC 1=J1L*SENGAC1+SEGAC SENERGAC - AVERAGE ENERGY GENERATION SENERGAC=J1L*SENGAC1+{.5*SEGAC)  CAPACITY FROM GAS TURBINES  SENCAC1 - ENERGY GENERATION CAPACITY FROM HAT CREEK AT YEAR SENCAC1=J1L*SENCAC1+SECAC  END  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 I F RTIME=75. THEN SCAPH=4186. I F RTIME>75. THEN SCAPH=31L*SCAPH+SCH SCAPB=900. I F RTIME=75. THEN SCAPG=327. I F RTIME>75. THEN SCAPG=J1L*SCAPG+SCG SCAPC=J1L*SCAPC+SCC SCAPK=J1L*SCAPK+SCK  CAPABILITY  K P I S _ $ 7 6 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 PLANT IN SERVICE KPISH$H=J1L*KPISH$H+PH$H KPISG$H=J1L*KPISG$H+PG$H KPISC$H=J1L*KPISC$H+PC$H I F A (2011)=0. THEN GO TO 508 I F A(2011)=1. THEN GO TO 590 I F A{2011)=6. THEN GO TO 580 I F A(2011)=7. THEN GO TO 710 IF A(2011)=8. THEN GO TO 560  GENERATION  IF IF IF IF IF 508 I F  A{2011) = 11. THEN GO A(2011) = 16. THEN GO A(2011) = 17. THEN GO A (2011) =21. THEN GO A (2011) NOT= 0. THEN A{2010) NOT= 0. THEN  TO 810 TO 860 TO 900 TO 940 GO TO 1010 GO TO 1010  184  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 I F RTIME>START1 THEN GO TO 520 I F RTIME=START1 THEN T1$76=13.8*A(1951) IT1$=PEXOG/2.11*T1$76 IDCT1$=5. IDC$=IDC$+IDCT1$ 52 0 I F RTIME>START2 THEN GO TO 530 I F RTIME=START2 THEN T2$76=11.4*A (1952) IT2$=PEXOG/2.11*T2$76 I F RTIME=(START2-1.) THEN IDCT2$=1.5 I F RTIME=START2 THEN IDCT2$=3.5 IDC$=IDC$*IDCT2$ I F 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 I F RTIME=START3 THEN T3$76=42.*A (1953) I F RT IM E= ( ST A RT 3 + 1. ) THEN T3$76=46. 5*A (1 953) IT3$=PEXOG/2.11*T3$76 I F RTIME=START3 THEN IDCT3$=3.0 I F RTIME=(START3+1.) THEN IDCT3$=5.0 IDC$=IDC$*IDCT3$ I F RTIME NOT= (START3+1.) THEN GO TO 540 PT$76=PT$76*(85.*A(1953) ) PT$H=PT$H+117. 540 I F RTIME>(START4+1.) THEN GO TO 560 I F RTIME=START4 THEN T4$76=15.2*A {1954) IT4$=PEXOG/2.11*T4$76 I F RTIME=(START4-3.) THEN IDCT4$=.5 I F RTIME=(START4-2.) THEN IDCT4$=1. I F RTIME=(START4-1.) THEN IDCT4$ = 1.5 I F RTIME=STAST4 THEN IDCT4$=3. IDC$=IDC$+IDCT4$ I F RTIME NOT= START4 THEN GO TO 560 PT$76=PT$76+ (85. * A (1954).) PT$H=PT$H+117. 560 I F RTIME>(START6+4.) THEN GO TO 578 I F RTIME=START6 THEN T6$76=3.*A( 1956) I F RTIME= (START6+1.) THEN T6$76=3.6*A{1956) I F RTIME=(START6 + 2.) THEN T6$76=14.2*A (1956) I F 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$76+(46.5*A(1956) )  578 580  588 590  600  708 710  PT$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$ I F a (2011) NOT= 0. THEN GO TO 1005 I F RTIME>(START8+5.) THEN GO TO 588 I F RTIME=START8 THEN T8$76=2. 2*A (1 958) I F RTIME= (START8+ 1.) THEN T8$76=8. *A (1 958) I F RTIME=(START8+2.} THEN T8$76=4.3*A{1958) I F RTIME= (START8 + 3.)., THEN T8$76=16. 9*A (1 958) I F RTIME= (START8+4.) THEN T8$76=34 . 9*A (1 958) I F 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$+IDCT8$ I F 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$ I F A(2011) NOT= 0. THEN GO TO 1005 I F RTIME>(START9+6.) THEN GO TO 600 I F RTIME=START9 THEN T9$76=7.*A{1959) IF RTIME= (START9+1.) THEN T9$76=4.1*A(1959) I F RTIME=(START9+2.) THEN T9$76=1.2*A (1959) I F RTIME= (START9 + 3.) THEN T9$76=.7*A (1959) I F RTIME={START9+ 4.) THEN T9$76=2.8*A (1959) IF RTIME=(START9+5.) THEN T9$76=5.7*A ( 1959) I F 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$+IDCT9$ I F 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$ I F RTIME> (START 10 + 5.) THEN GO TO 708 I F RTIME=STAHT10 THEN T10$76=1.*A{1960) I F RTIME= (START10 + 1.) THEN T10$76= 1.*a (1 960) I F RTIME=(START 10*2.) THEN T10$76=3.*A (1960) I F RTIME=(START 10 + 3.) THEN T10$76=5.5*A (1960) I F RTIME= (START 10+4.) THEN T 10$76=6. 7*A (1960) I F 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$+IDCT10$ I F 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$ I F A{2011) NOT= 0. THEN GO TO 1005 I F START21=0. THEN GO TO 808 I F RTIME>(START21+4.} THEN GO TO 808 I F RTIME=STaRT2 1 THEN T2 1$76=4. 9*A { 1 97 1) I F RTIME= (START21 * 1.) THEN T21$76=5.9*A(1971) I F RTIME=(START21+2.} THEN T21$76=23.2*A (1971)  808 810  858 860  880  I F RTIME=(ST1RT21+3.) THEN T21$76=27.4*A (1 97 1) 186 I F 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 $* J 3 L * I T 2 1 $ + J 4 L * I T 2 1 $ * J 5 L * I T 2 1 $ + J 6 L * I T 2 1 $) IDC$=IDC$+IDCT21$ I F 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$ I F A (2011) NOT= 0. THEN GO TO 1005 I F RTIME>(START31+2.) THEN GO TO 858 I F 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$*IDCT31$ I F 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$ I F A(2011) NOT= 0. THEN GO TO 1005 I F RTIME<START36 THEN GO TO 1005 I F RTIME>(START36+6.) THEN GO TO 880 I F RTIME=START36 THEN T36$76=2.3*A{1986) I F RTIME=(START36*1.), THEN T36$76=2. 6*A{ 1986) I F RTIME=(START36+2.) THEN T36$76=.7*A (1986) I F RTIME=(START36+3.) THEN T36$76=8.5*A(1986) IF RTIME=(START36+4.) THEN T36$76=16.7*A(1986) I F RTIHE=(START36+5.) THEN T36$76=5.8*A(1986) I F 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$+ J 3 L * I T 3 6$+J41*IT36$+J5L*IT36$+J6L*IT36$) IDC$=IDC$+IDCT36$ I F 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$ I F RTIME> (START38+5.) THEN GO TO 898 I F RTIME=START38 THEN T38$76=.4*A (1988) I F RTIME=(START38+1.) THEN T38$76=1.5*A{1988) I F RTIME=(START38+2.) THEN T38$76=.8*A(1988) I F RTIME= (START38+3. ) THEN T38$76=3. 1 * A (1 988) I F RTIME=(START38 + 4.) THEN T38$76= 6. 4*A{ 1988) I F 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$* J 3 L * I T 3 8$+J4L*IT38$+J5L*IT38$+J6L*IT38$) IDC$=IDC$+IDCT38$ I F 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$  898 900  IF A(2011) NOT= 0. THEN GG TO 1005 187 I F RTIME>(START40+6. ) THEN GO TO 938 I F RTIME<START40 THEN GO TO 1005 I F RTIME=START40 THEN T40$76=1.*A { 1990) I F RTIME= (START40 + 1.) THEN T40$76=.8*A (1990) I F RTIME=(START40+2.) THEN T40$76=1. 4*A (1990) I F RTIME=(START40+3.) THEN T40$76=2.7*A (1990) I F RTIME= (START40+4.) THEN T40$76=3. 7*A (1990) I F RTIME=(START40+5.) THEN T40$76=6.9*A{1990) I F 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$+IDCT4 0$ I F 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 I F A(2011) NOT= 0. THEN GO TO 1005 940 I F RTIME>(START44+6.) THEN GO TO 950 IF RTIME<START44 THEN GO TO 1005 I F RTIME=START44 THEN T44$76=.8*A{1994) I F RTIME= (START44+1.) THEN T44$76=2.9*A( 1994) I F RTIME=(START44*2.) THEN T44$76=2.4*A(1994) I F RTIME= (START44 + 3.) THEN T44$76=5. 4*A (1994) I F RTIME=(START44+4.) THEN T44$76=14.7*A{1994) I F RTIME=(START44+5.) THEN T44$76=14.*A(1994) I F RTIME=(START44+6.) THEN T44$76=7.6*A(1994) IT44$=PEXOG/2.11*T44$76 IDCT44$=A (1872) * { {. 5*IT44$) * J 1 L * I T 4 4 $ + J 2 L * I T 4 4 S + J 3 L * I T 4 4$+J4L*IT44$+J5L*IT44$+J6L*IT44$) IDC$=IDC$+IDCT44$ I F RTIME NOT= (START44+6.) THEN GO TO 950 PT$76=PT$76+(62.8*A(1994)) PT$H=PT$H+IT44$ + J 1 L * I T 4 4$+J2L*.IT44$+J3L*IT44$+ J 4 L * I T 4 4$*J5L*IT44$*J6L*IT44$+IDCT44$+J1L*IDCT44$+ J21*IDCT44$+J3L*IDCT44$+J4L*IDCT44$+J5L*IDCT4 4$+J6i*IDCT44$ 950 I F RTIME<START45 THEN GO TO 1005 I F RTIME> (START45 + 4.), THEN GO TO 1005 I F RTIME=START45 THEN T45$76=1.*A{1995) I F RTIME= (START45+ 1. ) THEN T45$7 6=2. * A (1 995) I F RTIME= (START45 + 2.) THEN T45$7 6=3 . * A (1995) I F 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$+ J 3 L * I T 4 5 $ + J 4 L * I T 4 5 $ + J5L<'IT45$ + J 6 L * I T 4 5 $ ) IDC$=IDC$+IDCT45$ I F 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 $ + J 5 L * I T 4 5 $ * J 6 L * I T 4 5 $ + 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 I N 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 HERE I F AVERAGE RAINFALL  ENERGY CAPACITY PERIOD  SENERHC=SENERHAC HERE I F CRITICAL I F A(2007)  RAINFALL PERIOD  NOT= 0. THEN  SENERBC - BORRARD»S  SENERHC=SENERHCC  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 IN SERVICE  MAJOR ASSOCIATED TRANSMISSION PROJECTS  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 IF  FOR COMPLETE SYSTEM  NTIME=75 THEN COPFIX$=108.6  I F NTIME>=76 THEN COPFIX$={108.6*PEXOG/1.95) + { {PEXOG/2. 11} *A (1853) * (J 1L*KPISH$76+ (. 4* (KPISH$76-J 1L*KPISH$76) ) ) ) + ( ( P E X O G / 2 . 1 1 ) * A ( 1 8 5 4 ) * ( J1L*KPISC$76* {.4*(KPISC$76-J1L*KPISC$76))))+ {(PEXOG/2. 11) * A ( 1 8 5 5 ) * ( J 1 L * K P I S G $ 7 6 + (.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 ( 1 8 5 7 ) * ( J 1L*KPISD$76+ (.4* (KPISD$76-J11*KPISD$76) ) ).) COPFIXU IF  - FIXED OPERATING COSTS TO 230 KV LEVEL  NTIME=75 THEN COPFIX1$=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 * { K P I S C $ 7 6 - J 1 L * K P I S C $ 7 6 ) ) ) ) + { (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$76) ) ) ) TWATER - WATER LICENCE COSTS IF IF  NTIME=75 THEN THATER=8.2 NTIME>=76 THEN TW ATER= (PEXOG/1.95) * A { 1860) * (J 1L* SCAPH + (.4* (SCAPH-J1L*SCAPH) ) ) +  (PEXOG/1.95)*A{1861)*SENERH  190  CGPVAR$ - 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 ( 1 8 7 7 ) * (J1L*KPISD$H+ (.4*(KPISD$H-J1L*KPISD$H)))  KDEP$76 - ACCUMULATED DEPRECIATION ON NEH NON-HYDRO-ELECTRIC F A C I L I T I E S FOR SCHOOL TAX PURPOSES I F NTIME=75 THEN IF  DEPACC$H=0.  NTIME>=76 THEN DEPACC$H=J1L*DEPACC$H+ (2.1 1/PEXOG* (DEPREC$-64.5-{A (1874)*(J1L*KPISH$H+(.4*(KPISHSHJ1L*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 * { J 1 L * K P I S $ 7 6 - J 1 L * K P I S H $ 7 6 J1L*DEPACC$H)))  TGRANTS -  'GRANTS'  I F NTIME=75 THEN IF  NTIME>=76  TGRANTS=3.3  THEN TGRANTS=A(1859)*J1L*YTOT  TLAND - LAND TAXES IF  NTIME=75 THEN  IF  NTIME>=76  TLAND=1.  THEN TLAND=J1L*TLAND*(1.+ {1.5*A (1972)))  TLOCAL - ALL LOCAL TAXES TLOCAL=TSCHOOL+TGRANTS*TLAND INTEREST  CHARGES  INTOLDB - ANNUAL INTEREST PAYMENTS TO 1976  REMAINING ON  BONDS ISSUED PRIOR  IF  HTIHE=75 THEN INTOLDB= A ( 1 867) *A (1 86 8) *A { 1 86 9)  IF  NTIME=76 THEN INTOLDB=A { 1 867) *A { 1 86 8) * { (J1L*INT0LDB+25.)- (•5*1NTRED$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 END OF EACH PERIOD IF  NTIME=75  THEN  IF  NTIME>=76 THEN LQLD$H=  1976 S T I L L OUTSTANDING  LOLD$H=2990.32 J1L*LOLD$H-LOLDM$H  SFPAYMT$ - ANNUAL SINKING FUND PAYMENT AND ADDITIONAL FUNDS REQUIRED FOR BONDS MATURING BEFORE 1982 IF  NTIME=75  THEN SFPAYMT$=34. 6*A (1 867)  IF  NTIME=76 THEN  IF  NTIME=77 THEN SFPAYMTJ=54. 0*A (1 867)  IF  NTIME=78  THEN SFPAYMT$=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  SFPAYMT$=35. 3 *A (1 867)  REQUIREMENTS  FINREQ=I$+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  191  AT  C1KWH$76={2.11*(COSTS$* (COVERAGE*INT$)-YEXPORT))/ (SENER*PEXOG) C2KWHS76 - COST PES KWH GENERATED  192  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  C01$76 - ANNUAL PRESENTLY UNCOMMITTED OPERATING COSTS (ALL VARIABLE AND POST-74 FIXED) TO SERVE LARGEST CUSTOMERS C01$76= 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) IF  K7=M9 THEN KPVC3$76=KPVC3$76/((1.+A (1894) )**{K7-2) )  KPVC4$76 - PRESENT VALUE OF COSTS ASSOCIATED WITH SUPPLYING SMALLEST CUSTGMERS  193  KPVC4$76=(1.+ A ( 1 8 9 4 ) ) * J 1 L * K P ¥ C 4 $ 76 + ( C O 2 $ 7 6 * ( A ( 1 8 5 0 ) * (J1L*KELEC4*IGEN$76+ITRS$76+ITRF$76+IDIST$76))+ C(A (1890)+AC1895))*.5* ( K E L E C 4 + J 1 L * K E L E C 4 ) ) ) * (<1.*A(1894))**.5) IF  K7=M9 THEN KPVC4$76=KPVC4$76/{ { 1.+A (1 894) ) * * (K7-2) )  SUBROUTINE RATES  THIS SECTION CALCULATES REVENUES AND RATES THAT ARE ESTABLISHED BY B C HYDRO IN RESPONSE TO THE COSTS FACING I T AND I T S FINANCIAL POLICIES  DETERMINE REVENUES FROM ELECTRICITY  YRES - REVENUE FROM RESIDENTIAL  SALES  SALES  YRES=PRES*DRES YGEN - REVENUE FROM GENERAL  SALES  YGEN=PGEN*DGEN YBULK - REVENUE FROM BULK  SALES  YBULK=PBULK*DBULK YWKPL - REVENUE FROM WKPL SALES YWKPL=PWKPL*DWKPL YEXPORT - REVENUE FROM EXPORT  SALES  YEX PORT=PEX PORT *DEX PORT YTOT - TOTAL REVENUES YTOT=YRES+YGEN+YBULK+YWKPL+YEXPORT MISS— FRACTION OF REVENUE  SURPLUS/DEFICIT  MISS=(COSTSS+(COVERAGE*INT$) -YTOT) / (YTOT-YEXPORT) DETERMINE AVERAGE  RATE LEVELS  ($/KWH)  PEES - AVERAGE RESIDENTIAL RATE I F (NTIME.EQ.75)  PRES=.023  IF(NTIME.EQ.76)  PRES=.027  IF(NTIME,GE.77)  PRES=J1L*PRES* (1.+MISS)  194  PGEN - AVERAGE GENERAL .RATE I F (NTIME.EQ.75)  PGEN=.020  IF(NTIME.EQ.76)  PGEN=.023  I F (NTIME. EQ.77) PGEN = .026 IF(NTIME.GE.78)  PGEN=J1L*PGEN* (1.+MISS)  PBULK - AVERAGE BULK RATE IF(NTIME.EQ.75)  PBULK=.007  I F (NTIME.EQ.76)  PBULK=.010  IF(NTIME.EQ.77)  PBULK=.011  I F (NTIME. EQ. 78)  PBULK=.012  IF(NTIME.EQ.79)  PBULK=.0134  I F (NTIME.GE. 80) PBOLK=J 1L*PBULK* (1.+MISS) PIKPL - AVERAGE WEST KOOTENAY  POWER AND LIGHT RATE  I F (NTIME.EQ.75) PSKPL=.0146 I F (NTIME.EQ.76)  PWKPL=.0186  IF(NTIME.EQ.77)  PWKPL=.0195  I F (NTIME. GE. 78) PWKPL=J 1 L*PWKPL* (1.+MISS) PEXPORT - AVERAGE EXPORT PRICE I F (NTIME.GE.75) CONVERT CURRENT  PEXPORT= A {1879) * (PEXOG/1.77)  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$76=A (1879) YRESMCP - REVENUE FROM RESIDENTIAL SALES UNDER FULL  MCP  YRESMCP=A(2014) *PEX0G/2. 11*DRES/1000-  195  YGENMCP - REVENUE FROM GENERAL SALES UNDER FULL  MCP  YGENMCP=A (2016) *PEXOG/2.11*DGEN/1000. YBULKMCP  - REVENUE FROM BULK SALES UNDER FULL  MCP  YBULKMCP=A(2018)*PEXOG/2.11*DBULK/1000 YSURPMCP  - ADDITIONAL B.C. HYDRO NET INCOME  UNDER FULL  YSURPMCP=YRESMCP+YGENMCP*-YBULKMCP*YWKPL+YEXPORT -COSTS$-(COVERAGE*INT$) YTOTSURP - TOTAL B.C. HYDRO NET INCOME UNDER FULL YTOTSURP=YSURPMCP+(COVERAGE*INT$) YTOTMCP - TOTAL REVENUE FROM SALES UNDER FULL  MCP  YTOTMCP=YRESMCP*YGEN MCP+ YBULKMCP* Y WKPL*-Y EXPORT IF(NTIME.LT.81)  YTOTMCP=YTOT  MCP  MCP  

Cite

Citation Scheme:

        

Citations by CSL (citeproc-js)

Usage Statistics

Share

Embed

Customize your widget with the following options, then copy and paste the code below into the HTML of your page to embed this item in your website.
                        
                            <div id="ubcOpenCollectionsWidgetDisplay">
                            <script id="ubcOpenCollectionsWidget"
                            src="{[{embed.src}]}"
                            data-item="{[{embed.item}]}"
                            data-collection="{[{embed.collection}]}"
                            data-metadata="{[{embed.showMetadata}]}"
                            data-width="{[{embed.width}]}"
                            async >
                            </script>
                            </div>
                        
                    
IIIF logo Our image viewer uses the IIIF 2.0 standard. To load this item in other compatible viewers, use this url:
http://iiif.library.ubc.ca/presentation/dsp.831.1-0094435/manifest

Comment

Related Items