c. Zuker and Glenn P. Jenkins, in collaboration · of conclus10ns or reco!!lmendat10ns by etther...
62
j :' A paper prepared for the Economic Council of Canada P.O. Box 527 Ottawa, Ontario KiP 5V6 • •! ,, Un document prepare pour le Conseil economique du Canada C.P. 527 Ottawa (Ontario) KiP 5V6 Statistical Appendices to BLUE GOLD: Hydro Electr_ic Rent in ea·nada by Richard c. Zuker and Glenn P. Jenkins, in collaboration with Henry Lim and Pierre Poirier c §®&®©@ • • Susitna Joint Venture Document Number Please Return To DOCUMENT CONTROL -
Transcript of c. Zuker and Glenn P. Jenkins, in collaboration · of conclus10ns or reco!!lmendat10ns by etther...
j :'
A paper prepared for the
Economic Council of Canada
P.O. Box 527 Ottawa, Ontario KiP 5V6
• •! ,,
Un document prepare pour le
Conseil economique du Canada
C.P. 527 Ottawa (Ontario) KiP 5V6
Statistical Appendices to
BLUE GOLD: Hydro Electr_ic Rent in ea·nada
by Richard c. Zuker and Glenn P. Jenkins, in collaboration with Henry Lim and Pierre Poirier
fMJ&rffi~& c §®&®©@
• •
Susitna Joint Venture Document Number
Please Return To DOCUMENT CONTROL
-
\I
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Statistical Appendices to
BLUE GOLD: ifY'dro Electric Ren·t ·in· ea·nada
by Richard C. Zuker and Glenn P. Jenkins, in collaboration with Henry Lim and Pierre Poirier
0
Fall 1984
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Table of Contents
Page
Appendix A - Supplementary Tables to Chapter 3 1
Appendix B - Supplementary Tables to Chapter 4
Appendix C - Description of the Procedure
to Estimate the Provincial
Distribution of the Rent on
Hydro-Electricity Generated
by Electric Utilities on the
7
Basis of Consumption 34
Appendix D - Supplementary Tables to Chapter 5 48
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Appendix A
Supplementary Tables to Chapter 3
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Table A.l
Economic Prices of Fuel and Variable Operating Costs 1'979-1980
British Quebec Ontario Manitoba Columbia
{$ per Mwh) Operating Fuel Costs
Nuclear 1979 $ 2.10 $ 2.10 $ 2.10 $ 2.10 1980 2.31 2.31 2.31 2.31
Coal 1979 18.86 18.08 15.38 9.04 1980 20.49 19.89 16.90 9.95
J6 Fuel Oil 1979 64.37 64.37 64.37 64.37 1980 65.79 65.79 65.79 65.79
#2 Fuel Oil 1979 111.25 111.25 111.25 111.25 1980 113.70 113.70 113.70 113.70
Variable Operating and Ma ilntenance Costs
Nuclear 1979 $ 2.00 $ 2.00 $ 2.00 $ 2.00 1980 2.20 2'.20 2.20 2.20
Coal-Ste~m 1979 1.30 1.30 1.30 1.30 1980 1.43 1.43 1.43 1.43
Oil-Fired StBam 1979 1.20 1.20 1.20 1.20 1980 1.32 1.32 1.32 1.32
Gas Turbine 1979 3.39 3.39 3.39 3.39 1980 3.73 3.73 3.73 3.73
Sources Basic Fuel prices from Department of Rnergy, Mines and Resources, Energy Reference Cost Premiums, 1980. Estimations of cost per mwh made by C.T. Main Engineering, Systems Planning Division, Roston, Mass. 1981.
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Table A.2
Generation Capacity Fixed Operation ·), Costs of and Costs .
(1979 prices)
( 1) ( 2) ( 3) ( 4) ( 5) Fixed ,,
Operating Forced Schedulecl, '··
Ulnit Cost and Heat Rate@ Availability Outage Maintenance .:'~· " \1 ·.
(Rated) Maintenance 75% Output Factor Rate Rat.e Type/Size (Mw) $/KW $/KW/YR BTU/KWH Per Cent Per Cent Per OeAjt,
-NUCLEAR (CANDU) ··:
' ,.? "'.,~;-;:":"""iJ;:-,:'...,._......,.,ttt
500 1,238 4.1 85.6 8 7
I I 6·00 1,212 4.1 85.6 8 7 700 1,187 4.1 84.1 9 7 800 1,163 4.1 82.6 10 ij ~;
850 1"151 4.1 81.9 10 9 W.·. 900 1,139 4.1 80.1 11 10 r~
1,000 1,115 4.1 78.3 11 10 I
Length of Life - 25 years
COAL 100 583 23.6 10,250 86.3 5.0 11.0 200 566 20.4 10,170 84.6 5.0 11.0 300 S49 17.2 10,060 81.8 6.0 13.0 400 532 13.9 9,940 81.5 8.5 14.0 500 516 12o5 9,875 76.5 10.0 15.0 600 501 11.1 9,810 76.5 10,0 15.0 700 486 9.9 9,750 76.5 10.0 15.0 750 479 9 .. 4 9,720 76.5 10.0 15 .• 0 800 471 8.8 9,680 76.5 10.0 15.0 900 456 8.3 9,680 75 .. 0 11.0 15.0
1,000 443 8.0 9,680 74.0 12.0 15,. 0
Length of Life = 25 years
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Table A.2 (Cont'd)
Costs of Generation Capacity and Fixed Operation Costs (1979 prices)
Type/Size (Mw)
OIL-FIRED STEAM
100 200 300 400 500 600 700 750 800 900
1,000
Length of Life - 25 years
GAS-TURBINE
20 40 60 80
100
Length of Life = 15 years
( 1 )
Unit Cost (Rated) $/KW
472 458 444 431 418 405 393 387 381 370 359
174 158 143 130 118
( 2) Fixed
Operating and
Maintenance $/KW/YR
23.6 20.4 18.2 13.9 12.5 11.5
9.9 9.4 8.8 8.3 7.3
0.32 0.32 0.32 0.32 0.32
Real econommic .cost o:f capit.a1 = 10 per cent
( 3)
Heat Rate@ 75% Output
BTU/KWH
10,350 10,270 10,160 10,040
9,980 9,910 9,850 9,815 9,780 9,780 9,780
14,000 13,800 13,500 13,000 12,500
Real financial cost of fun~s to utility = 3 per cent Adjustment of prices .of inflation = 10 per cent per year
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( 4 )
Availability Factor
Per Cent
86.3 85.9 81.5 81.5 80 .. 5 79.0 77.5 76.5 76.5 76.0 75.5
88.8 88.8 88.8 88.8 88.8
( 5)
Forced Outage
Rate Per Cent
5.14 5.48 8.5 8.5 8.5 9.0 9.0
10.0 10.5 11.0 12.0
8.0 8.0 8.0 8.0 8.0
(6) t'
Sched.aih.ed· MainteA~n.o·~ ·
Rate-, Per Cent
~-
1 o •. o 10.0 12.0 12.0 ·' 15.0 15.0 "" 15.0 15.0 15.0 15.0 15.0
'---:-
3.2 382 3.2 3.2 3~2
Sources Electric Power Research Institute (8PRI), Technical Assessment Re~ort (EPRI PS-1201-SR) 1979, Ontario Hydro, CC?.,st Col}!parison of 4 X SOOMJT <;oal fuelled ana 4 XSOMW Candu Nuclear Gen~r9!::_J.J;)O stations, Report No. 5~5 SP, January 1981.
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Table J\.3
Generation Mix For Alternative 11111-Thermal Generation Systems, 197'9
Type of Generation
Nuclear
Coal
Oil
TOTAL
QUEBEC CAPACITY ENERGY
(MW) (MWH)
lJ,Go:o BEI,581, 745 (16 @ 850')
7,50'0 20,743,957 (10 @ 750)
3, 2001 1,266,752 (32 @ 1001)
24,3010 11 (),59 7~ ,, 4 54
ONTARIO CAPACITY ENERGY
(MW) (MWH)
12,750 81, 59'4, 7~55 (15 @ 850)
6,000 15,237,.:SIH (8 @ 750)
2,000 1, 277 ,81'0 (20 @ 100)
.20!, 750 9 8, 1 0 9 , ~lll6
f'IIANITOBA CAPACITY ENERGY
(MW) (MWH)
3,000 (10 @ 300)
520 (13 @ 40)
3,520
13,814,01JL
1i802,70i8
15, 616, 71'9
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BRITISH COLUMBIA CAPACITY ENERGY
(MW) (MWH)
6,000 (12 @ 500)
2,400 (40 @ 60)
8,400
33,931,759
7,261 .. 121
41,182,880
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Table A. 4
Load and Capacity Factors for Alternative All-Thermal Systems, 1979
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SY:STEM LOAD FACTOR {per cent)
CAPACITY FACTOR
NUCLEAR
COAL
OIL/TURBINE
QUEBEC ONTARIO MANITOBA
65.2 68.5 70.1
74.4 73 •. 1
31.6 29.0 52 .. 6
4.5 7.3 39.6
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BRITISH COLUMBU{ . ,
69.6
64.5
34.5·
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Appendix B
Supplementary Tables to Chapter 4
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Table B.1
Economic Cost of Current System: Elecl!.ric Utilities, 1979: Quebec and Ontario
Generation Capacity Cost
1. Gross Generation Capital Stock ( Histor,ical) ( $000)
2. Net Current/Gross Historical Capital Stock, 1979 (Ratio)
3. Net Generation Capital Stock at 1979 Prices ($000)
4. Rate of Ecor.omic Depreciation
5. Economic Depreciation
6. s.o.c. of Genera.tion Capital @10%
1. Total Annual Cost - Generation Capital
Fuel Cost
8. Uranium@ $2.10/MWH
9. Coal
10. Coal
11. Heavy
@ $18.08/MWH
@ $18.83/MWH
Fuel Oil @ $62.60/MWH
12. Diesel (i Light Fuel Oil @ $111.20/MWH
13. Natural Gas @ $62.60/MWH
14. Total Annual Cost - Fuel
Generation Operating And Maintena'-!'"'0 Fixed Cost
15. Nuclear @ $4.10/k.W
16. Coal @ $12.50/kW
17. Oil @ $12.50/kW
.18. Internal Combustion @ $12.50/kW
19. Gas Turbine @ $0. 32/kW
10. Hydro @ $3.00/kW
21. Total Annual Cost - Gene rat ion Operating ' Maintenance - Fixed
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Quebec ---$666 $000
4,404,929
1. 4535
6,402,564.3
,0266
170,308.;2
6-&0,256.4
810,564.6
MWH
21,893 1,370.5
149,478 116,622.0
17,992.5 17 ;-992. 5
MW
266.4 1,092.2
600.0 7,500.0
76.4 955.0
312.7 100.1
14,182.0 42,546.0
52,-f!fJ. 3 12, !..~.~- 3
6,495,641
1. 4796
9,610,950.4
.032.5
MWH
33,272,359
28,422,622
875,366
154,464
1,473,668
HW
5,600.0
12,259.0
10.0
450.6
G,786.6
Ontario -s-mro--
312,355.9
961,095.0
1,273.450.9
69,871.9
513,881.0
54,797.9
17,176.4
92,251,6
747,978.8
22 .. 960.0
153,237.5
125.0
144.2
20,359.8
T96;-826"3
$000
00
747,978.8
r/ .,
196~~26. 5
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Table B.l (conl'd)
Generation Ope~ating and Maintenance - Variable Cost
22. Nuclear @ $2.0/MWH
23. Coal @ $1.3/MWH
24. Oil, Diesel, Gas @ $1.2/MWH
25. Oil, Diesel, Gas @ $3.4/MWH
...
26. Total Annual Cost - Generation OpQ.ratino " Maintenance-Vcsriable.
Economic Cost of .Power Purchased:
27. Fr011 Churchill Fcslls at Border
28. Cost of Other Power 'Purchased
29. Cost of Power PUitchased - Total
30. Econoaic Cost of Energy Produced and Purchased - Sub-total
Tran .. ission - Capital Cost
31. Gross Transaistion Capital Stock (Histocical) ($000)
32. Net Current/Gross Historical Capital Stock, 1919
33. Net Transaission Capital Stock at 1979 Prices ($000)
34. Rate of Econoaic Depreciation
35. Economic Depreciation
36. s.o.c. of Transaission Capital at 101
37. Total Annual Cost - Transmission Capital
HWH
168,473
2,898 171,371
2,614,005
1.4535
3,799,456.3
.0266
sooo
202.2
9.9
212:1
211,279.0
7,695.0
218,974.0 21~,974.0
1,099,936.5
101,065,5
379,945.6
481,011.1 48l;orr:r
MWH
33,272,359
28,422,622
2,494,441
9,357 64,198,479
2,474,779
1.4796
3,661,683.0
.0325
66,544.7
36,9.(9.4
2,993.0
31.8
106,518.9
83,724.0
83,724.0
119.,004.7
366,168.3
485,173.0
,,
.$000
106.518.~
'2";'iD8 ,499 .1
0
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485,173.0
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Table B.l (ccnt'd)
Distribution - Capital Cost
38. Gross Distrabutton Capital Stock (Historacall ($000}
39. Net Current/Gross Historicol Capital Stock, 1979 (Ratio}
40. Net Tranaaisalon Capital Stock at 1979 Prices ($000)
41. Rate of Econoaic Depreciation
42. ~conoaic Depreciation
43. s.o.c. of Distr.ibution Capital @lOt
44. Total Annual Co•t - Distribution Capital
Tranuiuion OperaUng ' Maintenance Annual Coat
45. 0 • M Tranaaisaion Coat
Qperatib! • Maintenance ' Adain. Coet - D atribution • Other
45. Total 0 • M ' A - Actual
47. Leaaa Actual Fuel Coat
48. Le••• 0 • M Generation - Fixed
49. Leaal 0 ' " Generation - variable
50. Less: 0 ' M Tranaa.leaion
51. ~quala r o, M • A Coat - Other
Capital Cost of Other Fixed Aaaeta Other Property and EqUip-.nt
52. Gro3a Capital Stock (Hiatorlcal) ($000)
53. Net Current/Groee Historical - Ratio
54. Net t ·~ Hal Stock at 1979 Prlcea Otb~t !quip .. nt • Property ($000)
other 71xed Aaseta
55. Met Capital StocX (H!etorica1) (SOOO)
56. Net Current/Net Hlatorical - Ratio
57. Net Capital Stock at 1979 Prices
58. Net Capital Stock at 1919 Prices TOtal - All Other Fixed Aaaeta (SOOO)
59. Rate of !conoalc Depreciation
60. Econo•ic Depreciation
61. s.o.c. of Other Flxed Asaeta @ 10'
62. TOtal Annual Coat - Other Fixed ~asets
r
1,893,639
1.4535
2,752,404.3
421,744
1.4535
613,004.9
108,805.0
1. 7158
186,687.6
799,692.5
.0266
Quebec sooo
73,214.0
275,240.4
348,454.4
604,018.0
-8, ~3j,.O
-52,19.1.3
-212.1
-63,924.0
sooo
348,454 .•
63,924.1J
479,355.6 479,355.6
21,271.8
79,969.2
101,241.0
1,97!#,221
1.4'/96
2,928,455.4
.0325
851,326
1. 4796
1,259,621.9
10,854.0
1. 9080
20,709.4
1,280,331.1
.0325
Ontar1o $000
.95,174.8
292,845.5
l88. o2o. 3
1,398,302.0
-580,971.7
-196,826.5
-106,519.9
-67,856.8
446,1211.1
41,610.8
128,033.1
169,643.9
sooo
388,020.1
67,1156.8
U6, 128.1
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l Table 8.1 (cant 'd) l ! i
~ \ftnnual Opportunity Cost of l.9ther Assets
' t
1 63; Cash & Temporary Investments {$000) j
:64. Accounts .Receivable (SOOO)
65. Inventory ($000)
66. Other Assets ($000)
:67. Less: Accounts Payable & Accrd. Liab. ( SOOO)
68. Net Total - Other Assets ($000)
69. s.o.c. of Other Assets @ 10\
70. Total Economic Cost of Current System
206,276.0
643,138.0
137, 58 4. 0
176,440.0
-601,735.0
561,703.0
OuE>hec -$000
56,170.3
$000
579,334.0
410,719.0
758,892.0
564,331.0
-1,040,902.0
1,272,374.0
Ontario -souo--
127,237.4
sooo
127,237.4
4,092,55if:6
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Table n.l
Economic Cost of Current system: Electric Utilitu~s, 1979: Manitoba and Hn t ish Columbia
Manitoba British Columbia - ·-soo£J sooo ------sooo - $000 Generation Ca(!acit~ Cost
~::. 1' Gross Generation Capital Stock (Historical) (SOOO) 1,750,507 2,192,318 " :-:.."'
,, '"'~ r;;r;,g' 2. Net Current/Gross Historical
; •' ; \.~-Capital Stock, (Ratio) 1.5207 1. 5241
3. Net Gen~ration Capital Stock at 1979 Prices ($000) 2,661,996.0 3,341,311.9
\/ '-~) t,~ .c. Rate of Economic Depreciation .0284 • 0261 -
5. Economic Daprecia t ion 75,600.7 93,890.9 (~~ ~·',L·"~-... ~
6o s.o.c. of Generation Capital @10\ 266,199.6 334,131.2
I 341,800.3 341,800.3 f) 7. Total Annual Cost - Generation Capital 429,022.f 428,022.1
I Fuel r.:ost ~ ~ ,,.
•· a. Uranium @ $2.10/HWH
9. Coal @ $18.08/HWH
1 o. Coal @ $18.83/HWH 49,128 925.1 11. Heavy Fuel Oil ll $62.60/HWH -21,079 -1,319.5
I 12. Diesel Light Fuel Oil @ $111. 20/l1WH SO,G65 5,656.2 81,772 9,093.0 \'-\ f,
&
-· 'J--:1 ;,
" 13. Natural Gas @ $62.60/MWH 923 57.8 472,417 29,573.3 N ,j
14. Total Annual Cost - Fuel 6,639.1 ~-639:-f 37,346:8 37,346.8 (< Generation 0Eerating And
Maintenance Fixed Cost MW MW 15. Nuclear @ $4.10/kW
16. Coa.l @ $12.50/kW ~19.0 5,237.5 17. Oil @ $12.50/kW
9!2.5 "11, 406. 2 18. Internal Combustion @ $12.50/kW 29.1 363.8 99.1 1,238.8 19. Gas Tur.bine @ SO. 32/kW 23.8 7.6 350.4 112.1
,,:;; 20. Hydro @ 53.00/kW 3,641.1 10,923.3 6,140.7 18,422.1 i,;·
21. Total J\nnual Cost - Generation \!, Operating " Maintenance - fixed 16-,-532.2 16 _,_5 j"i:-2 '31, 179.2 31, f19:..~
oi~il!•fC&*:MPd!Utt1.t~L, m;.i.iie ~~f: flj$1Jj!X .. l'illt'lf ~-~~ ftf;.,:C"~~(Jir LifL¥11.,
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Table 8.1 (cont'd}
Generation OQerating an<! Maintenance - Variable Co~!_
22. Nuclear @ S2.0/HWH
23. Coal @ Sl.3/MWH
24. Oil. Diesel, Gas @ $1.2/MWH
25. Oil, Diesel, Gas @ $3.4/MWH
26. Total Annual Cost - Generation Operating ' Maintenance-Variable
Economic Cost of Power Purchased
27. From Churchill Falls at Border
28. Cost of Other Power Purchased
29. Cost of Power Purchased - Total
30. Economic Cost of Energ:i Produced and Purchased - Sub-total
Transmission - CaQital Cost
31. Gross Transmission Capital Stock {Historical) ($000}
32. Net Current/Gross Historical Capital Stock
33. Net Tl:"ansmission Capital Stock ~t 1979 Prices ($000}
' 34. l• ;< e of Economic Depreciation
35. Economic Depreciation
36. s.o.c. of Transmission Capital at
37. Total Annual Cost - Transmission
_8.5
·::·
Manitoba British Columbia '~
· -sooo · $000 ---$000 ____
$000
mwh mwh
49, 128 63.9
51,753 62.1 562,460 675.0
35 0. 1 -29,350 -99.8
IT6-:T i26:T 575.2 575.2
:;_~
.. , 102.0 20,077.0
102-:D roi:"o 20,071.0 20,077.0 0
.;!_f5, 1'99. 7 517,200.;!
........ :I
....... 160,137 1,107,SIJ9 lsJ
l. 5207 }. 5241
243,520.3 1,688,076.4
.0284 .0281
6,916.0 47,434.9
10% 24,352.0 168,807.6
Capital rr;-268:0 'jT;-268 :.9.. il6,242.5 216,242!.~
f
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Table B.l {cont'dl
Distribution - Capital Cost
38. Gross Transmission ' Distribution Capital Stock (H1storicall (SOOO)
19. Net Current/Gross Historical Capital Stock (R~tio)
40. Net Transmission Capital Stock at 1979 Prices ,( SOOO)
41. Rate of Economic Depreciation
42. Economic Depreciation
43. s.o.c. of Distribution Capital @10\
44. Total Annual Cost - Distr-ibution Capital
7ransmission Operating ' Maintenance Annu&l Cost
45. 0 ' M Transmission Cost
Operatin~ ' Maintenance ' Admin. Cost - Distribution ' Other
46. Total 0 ' M ' A - Actual
47. ~~ss: Actual Fuel Cost
48. Less: 0 ' M Generation - Fixed
49. Less: 0 ' M Generation - Var -
50. Less: 0 ' M Transmission
51. Equal: o, M ' A Cost - Other
Capital Cost of Other Fixed Assets Other Property and E9uipment
52. Gross Capital Stock (Historic&!) ($000)
53. Net Current/Groos Historical - Ratio
54. Net Capital Stock at 1979 Prices Other Equipment ' Property ($000)
Other Fixed Assets
55. Net Capital Stock (Historical) ($000)
56. Net Current/Net Historical - Ratio
57. Net Capital Stock at 1g79 Prices -
58. Net Capital Stock at 1979 Prices -Total - All Other Fixed Assets (SOOO}
59. Rate of Ec,nomic Depreciation
60. Economic Depreciation
61. s.o.c. of Other Fixed Assets ~ lOt
62. Total Annual Cost - Othec Fixed Assets
8.5
783,284
1. 5207
1,191,140.0
.0284
80,551
1.5207
122,493.9
1. 8531
122,493.9
.0284
Manitoba 5000
33,828.4
119,114.0
I5'2";' 9 4 2 • 4
114,447.0
-3,861.8
-16,532.2
-126.1
-10,000.0
83,926.9
3,478.8
12,249.!
15,728.2
$000
152,942.4
10,000.0
83,926.9
151728 • ~
'
British Columbta sooo
1,618,682
1. 5241
2,467,033.2
.0281
751,733
1.5241
1,145,716.3
1.8662
1,1.45,716.3
.0281
69,323.6
246,701.3
Jl6,026:9
244,039.0
-9,663.4
-H, 179.2
-575.2
-8,940.0
193,681.2
32,194.6
114,571.6
146,766.2
$000
316,026.9
8,940.(!
193,681.2
146,766.2
.,_,. tb.
'
tr
I I
'" l
L
Table B.l (cont'd)
Annual Opportuni'ty Cost of Other Assets
• t
63. Cash & Temporary Investments ($000)
64. Accounts Receivable ($000)
65. Inventory ($000)
66. Other Assets ($000)
67. Less: Accounts Payable & Accrd. Liab. ( $000)
68. Net Total Assets ($000)
69. s.o.c. of Other Assets @ 10%
70. Total Economic Cost of Current System
7,001.0
52,508.0
23,692.0
81,267.0
-27,462.0
137,006.0
Manitoha $000
13,700.6
$000
13,700.6
672,765.8
'" ij I·
British Columbia $000
297,845.0
157,560.0
54,231.0
41,746.0
-353,400.0
197,982.0
19,798.2
. . ~· . . . . . . " .
$00()
19,'798.2
1,418,655~3 I'
),) ,\
r
Nete; ,A!~ data are from Statistics Canada, Electric Power Sta~istici>', Volume II, Annua.l Statistics Cat. t57-202 v 1979, unl~ss otherwise indicated.
Line No.
(1)
{~)
( 3)
{4}
( 5) ... ( 6)
( 7)
( 8)
( 9) r
(11)
(12)
(13)
( 14)
(10)
(15)-(20)
(15)
(16} 1 ( 17)
(18)
(19)
( 20)
(21)
(22)-(25)
(22)
(23)
(24)
(25)
{~6)
(27)
(28)
. ·r I l ,, r ,, ;.
·~ I
Table 13 (Total Utilities), line 1.
Based on estimates for Miscellaneous Utilities provided by the National Wealth and Capital Sto:~k Section of Statistics Canada.
(1) X (2).
Source same as for (2).
(3) X (4) •
(3) X 0.10.
(5) + (6).
MWH from Table
MWH from Table
MWH from Table
MWH from Table line 21.
11 (Energy
11 (Energy
11 (Energy
11 (Energy
Generated) line 24.
Generated) line 18.
Generated) line 20.
Generated) line 19 +
MWH from Table 11 (Energy Generated) line 23.
(8) + (9) + (10) + (!1) + (12) + (13).
Costs per MW are those presentd in Chapter 2.
MW from Table 1, footnotes 1 and 2.
MW from Table 1, line 9 less nuclear capacity for Ontario and Quebec from footnotes 1 and 2.
MW from Table 1, line 10.
MW from Table 1, line 11.
MW from Table 1, line 8.
(15) + (16) + (17) + (18) + (19) + (20).
Costs per MWH are those presented in Chapter 2.
MWH from Table 2, footnote (1).
f~WH from Table 11 (Energy Generated) 1 line 18.
MWH from Table 2, line 9 ~ (22) ~ (23) +Table 2, line 10.
l<iWH from Table 2, line 11.
(22) + (23) + (24) + (25).
From Table A.2.
For Quebec: Table 5 (Electric Utilities) value of Electricity Purchased, line 4 (page 22) less Table 5 (Electric Utilities),
---·· -
line 24 (page 20) for Newfoundland For other provinces: Table 5, line 4 (page 22) •
.,
_j
}'--""~,..,--.~-..,...._~."-~~,__,,_,._~.__..,,_,.'J'Oo 0 ~""'''*"'•d'W"'-'"""'-"
'
Notes to "I: able B.l ( cont 'd)
Line
(29)
(30)
(31)
(32)
(33)
(34)
(35)
(36) .. (37)
(38)
(39)
(40)
( 41)
(42)
( 4 3)
(44)
( 4 5)
(46)
( 4 7)
( 4 8)
( 4 9)
(50)
(51)
(52)
(53)
(54)
(55)
(56)
(57)
(58)
(59)
(60)
(61)
(62)
No. ,;
,,
(27) + ( 28} ~
(7) + (14) + (21) + (26) + (z9).
Table 13 (Total Utilities), line 2.
( 2) •
(31) X, (32).
( 4 ) •
( 33) X (34) •
(33) X 0.10.
(35) + {36).
Table 13 (Total Utilities), line 3.
( 2) •
(38) X (39).
( 4 ) •
(40) X (41).
{40) X 0.10.
(42) + (43).
These are unofficial estimates obtained from the utilities.
Table 14 (Total Utilities), line 4.
Table 11 (Cost of Fuel Used), line 12 (page 32).
( 21 ) •
( 26) •
( 4 5) •
(46)- (47)- (48)- (49)- (50).
Table 13 (Total Utilities), line 4.
( 2) •
(52) X (53).
Table 13 (Total Utilities), line 10.
Source same as for (2).
(55} X (56).
(54)+ (57).
( 4) •
(58) X (59).
(56) X 0.10.
( 60) + ( 61) •
--":"
r.:.·
J.o • co
'' i'
G
- 1~,
Nptes to Table 8.1 (cont'd)
Lin~ No.
(~3)
(64)
(65)
{66)
(67)
(68)
( 6-9) .. (70)
Tabl~~ 13 (Total Utilities), line 12 + line 13. '.\ \ ~
Table)! 13 (Total Utilities), line 14. J/
T~bJ·.e 13 (Total Utilities), line 15.
Table 13 (Total Utilities) line 16 + line 21 + line 22 + line 23.
Table 13 (Total Utilities), line 26.
( 63} + ( 64} + ( 65) + { 66) - ( 67) •
(68) X 0 .. 10 •
(30) + (37) + {44) + (45) +(51)+ (62) + (69).
___ .,
. '
Q
,I
19
Table 8~2
Estimated Economic Cost of Energy Purchased by Quebec from Churchill Falls (At The Border), 1979
Net Replacement Value of Fixed Capital - 1979 ·Dollars
1. - EnC: of Year, 1978
2. - End of Year, 1979
3. - Mid-Year, 1979
4. Economic Depreciation
s; Social Opportunity Cost of .. Capital, at 10 per cent
6. Total Cost of Capital
02eratin2, Maintenance and Administration Costs
7. Plant Operations
B. General Management
9. Major Repairs
10. Townsite Services - net cost
11. Retail Operations - net cost
12. Total OM&A Cost
13. Total Economic Cost of Energy Produced
Energy Sold
14. - to Labrador - at end of transmission network
15. - to Quebec - at border
16. Total Energy Sold
17. Proportion of Energy Sold to Quebec
18. Economic Cost of EnergYPurchased by Quebec
r--.~----.,
($000) ($000)
1,868,356.6
1,843,627.6
1,855,992.1
29,222.0
185,599.2
214,821.2
4,674.0
1,917.0
1,246.0
2,452.0
158.0
10,447.0
225,268.2
(MWH)
2,333.0
35,220.8
37,553.8
.9379
211,279.0
\' 'I ,.
IJ) • co
I· ' ~ '
;(.
- 20 -
Notes to Table B.2
.Line No.
(1)
( 2)
( 3)
{ 4)
( 5)
{ 6)
( 7·)- (12)
.. (13)
(14)-(15)
(16)
( 17)
(18)
Line (12) for 1978, from Table ·A.3.
Line (12) for 1979, front Table A.J.
0.5 [(1) + (2)].
Line (10) for 1979, from Table A.3.
(3) X 0.10.
(4) + (5).
Estimates provided by Newfoundland and Labrador Hydro •
(6} + (12).
Estimates provided by Newfoundland and Labrad0r Hydro.
(14) + (l5).
(15) ~ (16).
(13) X (17).
\'
.,
,,--.$,1oc'-'if4'P·,•~i-....,;jot .. ~ t
I I
I
8.5
. " 1:
Table B. 3
' Estimation of the Repl1acement Value of Net Fixed Capiitatl for Churchill Falls, 19'79 {in Current Dollars)
1. Gross Fixed Capit~l Cost at Original Price~
2.. Accumulated Deprec1iation
3. Net Value of Fixed! Capital at Cost
4. Annual Depreciation
5. Gross Investment a~ Cost
6. Implicit Price Deflator for Fixed Capital, 1979=100
7. Gross Investment, .1979 Dollars
B. Gross Fixed Capita~ Stock - 1979 Dollars
9. Economic Depreci~lt ion Rate
10. Economic Depreciation - 1979 Dollars
11. Accumulated Economi1C Depreciation - 1979 [):)liars
12. Net Replacement Value of F i x. e r:J Cap i t a 1 - 1 9 7 9 Do 11 a r s
ll9ill7 1968
42,013.8 113,799.3
3,423.11 4,287.3
38,590.i7 109,512.0
3,423.[ 864.2
42,013.8 71,785.5
39.42 39.52
106,579.9 181,643.5
106,579.9 288,223.4
0 0
0 0
0 0
106,579.'9 288,221.4
1i9:69 CSOOtJI)
242,:571,.5
5,'012 .. 7
237,558.8
725.4
128,772.2
40.90
314,846.5
603,069.9
0
0
0
6.0 3, 069. 9
1970 1971
.4471470.8 602,477.0
5,747.5 6,560.0
441,723.3 595,917.0
734.8 812.5
2.04 r 899. 3 155,006.2
44.54 4.6. 58
4150,034.4 332,774.2
1,063,104.3 1,395,878.5
0 0
0 0
0 0
1,063.104.3 1,395,878.5
';i '.
~ r' ·.,.
·~
-C· ~~1t!M!LJhlff?IM!fiU~Msttjrf'; !lt]"!ii!liRll.~··-•:fi ~-.11!1~ ~J~ Jtf."tt'~'tifJf;.:~Jimt.:~ -;.::1
·. , -~ "· ... _ . --~······~ .. .. .: ._ ... __ Jl .... -------·-·· _______ ,;.__. __________ . --··-·· --~~·.:: ...... ~ ...... ~ ....... :-:: ..... _:-:-_ . -===----~~L..i~~~iii
I I
Table 8.3 (cont'd)
4 Estimation of the Replacement Value of Net Fixed Capital for Churchill Falls, 1979 (ill Current Dollars)
1. Gross Fixed Capital Cost at Original Prices
2. Accumulated DP.preciation
3. Net Value of Fixed Capital at Cost
4. Annua] Depreciation
5. Gross Investment at Cost
6. Implicit Price ~fl~tor for Fixed Capital, 1979=100
7. r.{'qss Investment, 1979 Dollars •
8. Gross Fixed Capital Stock - 1979 Dollars
9. Economic Depreciation Rate
10. Economic Depreciation - 1979 Dollars
11. Accumulated Economic Depreciation - 1979 Dollars
12. Net Replacement Value of Fixed Capital - 1979 IXlllars
1972
716,242.0
8,608.0
707,634.0
2,048.0
113,765.0
48.72
233,507.8
1973 1974 ($000)
798,450.0
12,514.0
785,936.0
3,906.0
82,208.0
52.35
157,035.3
841,678.0
19,192.0
822,486.0
6,678.0
43,228.0
61.57
70,209 • .5
1975
950,032.0
29,988.0
920,044.0
10,796.0
108,354.0
71.91
150,680.0
1,629,386.3 1,786,421.6 1,856,631.1 2,007,311.1
.00286 .00489 .00793 .01136
4,660.0 8,735.6 14,723.1 22,803.1
4,660.0 13,395.6 28,118.7 50"921.8
1,624,726.3 1,773,026.0 1,828,512.4 1,956,309.3
•l!Mi91GJtMSfllftlf.l~~u. ·~1itftk,...1:ttrJ~i~$Jlj}l!fw:WXV':u _··t"·;.a )J#J@,-.:~U'/4:w:~··rcrr·,,rwr .. r ., it( r·t:~
. .
I I I ( 1 i
.. ~----- --.--·--~· .•. ____ ,...._.,_.,.'<-·~-- --""'---"'"··-~···-
..
Table B.3 (cont'd)
' Estimation of the Replacement Value of Net Fixed Capital for Churchill Falls, 1979 (in Current Dollars)
1. Gross Fixed Capital Cost at Original Prices
2. Accumulated Depreciatioh
3. Net Value of Fixed Capital at Cost
4. Annual Depreciation
5. Gross Investment at Cost
6. Implicit Price Deflator for Fixed Capital, 1979=100
7. Gross Investment, 1979 Dollars
8. Gross Fixed Capital Stock - 1979 Dollars
9. Economic Depreciation Rate
10. Economic Depreciation - 1979 Dollars
11. Accumulated Economic Depreciation - 1979 IX>11ars
12. Net Replacement Value of Fixed Capital - 1979 Dollars
1976
945,521.0
43,684.0
901,837.0
13,696.0
-4,511.0
77.18
-5,844.8
1977 1978 ($000}
948,963.0
57,882.0
891,081.0
1·4,198.0
3,442.0
83.00
4,147.0
954,920.0
73,986.0
880,934.0
16,104.0
5,957.0
90.31
6,596.2
1979
959,413.0
87,891.0
871,522.0
13,905.0
4,493.0
100.0
4,493.0
2,001,466.3 2,005,613.3 2,012,209-~ ~.~;ri~7D2.5
.01449 .01496 .01686 .01449
29,001.2 30,004.0 33,925.9 29,222.0
79,923.0 109,927.0 143,852.9 173,074.9
1,921,543.3 1,895,686.3 1,868,356.6 1,843,627.6
c
l
IV w
Lt) • co
- 24 -
Not.es to Table B. 3
Line No.
(1) Sources: Churchill Falls (Labrador) Corporation, Limited, Annual Reports, 1967-1974 · Newfoundland and Labrador Hydro Annual Reports, 1975-1979.
The capital costs include both expenditures for related economic and social infrastructure and interest during construction.
(2) Sources same as (1).
{3) (1) (2).
(4) (2) - (2) for previous year • .. (5) (1) - (1) for previous year~
(6) Source: Statistics Canada, National Wealth and Capital Stock Section, estimates are for Electric Power and Gas Utilities, Canad?·
(7) (5) (6).
(8) (7) + (8) for previous year.
(9) Rate is assumed to be zero before production began in 1972. Thereafter it is calculated as (4) (1), since the depreciation rate used appears to be the economic rate, given the estimated lifetime.
(10) {8} X (9).
(11) (10) + (11) for previous year .
(12) (8) - (11).
i ... ·-----· -·······--·-··----- .... ,, l ~
-
;f •. it.+f*'iil'~r·J;llff~~tt rflt~nrttw- f;tE;;- ·pLJH.tiR awrx~,Ltnt::,;. ~4~Mt(; ;it_ .c Pwr:~,..,&-e!~
•
1'able B. 4
~-----------------
• •
Economic Cost of All-Thermal System: Electric Utilities, 1979: Quebec and Ontario
l
Generation Cost (Capital and O&Hl
1. Cost for Energy Generated (used to design all-thermal system)
2~ Cost for Energy Required at Source (adjusted for losses}
3. Energy Adjustment Factor
Fuel Inventory ' Advance Payments
~. Coal at $19.34/HWH
5. Uranium at $7.98/MWH
6. Oil at $30.29/HWH
7. Total Fuel lnv. + Adv. Payments
8. Times: Energy Adjustment Factor
9. At s.o.c. of Capital f 10\
10. Other Net Current Assets & Investments
11. At s.o.c. of Capital @ 10\
12. Total Annual Capital Cost of Other Fixed Assets Depreciation + s.o.c. of Capital f 10\
13. Total Annual Capital Cost of Distribution (Depreciation + s.o.c. l
14. Total Annual OH&A (Distribution t Other)
• 15. Annual Transmission Capital
Cost - Current System
16. Annual Transmission O'M Cost - Current System
17. Total Annual Transmission Cost -C'urrent System
18. Proportion of Current Transmission Cost for All-Thermal (if Hydro = 2x Thermal)
19. Transmission Cost -All-Thermal System
20. Total Annual Cost -All-Thermal Syst~m
MWH $000
110,592,454 3,252,020
106,375,008 3,127,988.0 3,127,988.0
0.96186
20,743,957 401,188.1
88,581,745 706,882.3
1,266,752 38,371.8
1,146,442.2
1,101,755.0
110,175.5
561,703.0
56,170.3
101,241.0
481,011.1
63,924.0
544,935.1
.51S9
MWH
98,109,916
111,36 7, 24 7
1.13513
15,237,591
81,594,755
'1,277,570
• 7872
Ontario --$000
2,864,800
$000
3,251,920.4 3,~51,920.4
294,695.0
651,126.1
38,697.6
984,518.7
1,117,556.7
425,782.0
485,173.0
67,856.~
553,029.8
lj2,578.2
169,643._2
()
-~,f~~~~1jt1(l@Ji'_Xt. t_j))~JiL IIB?f_-&ttJ,_._JI41t.,S !fl, APR'fP..X-!it.>itf!'l~, 8.5 . '
Table B.4 (cont'd)
Economic Cost of AU-Thermal System; Electric Utilities, 1979: Manitoba and British Columbia
I I
f .... 1
l
Generation Cost (Capital and O&M)
1. Cost for Energy Generated (used to design all-thermal system)
2. Cost for Energy Required at Source (adjusted for losses)
3. Energy Adjustment Factor
Fu2l Inventory & AdV<'~Jce Payments
4. Coal at $19.34/MWH
5. 'Jranium at $7.98/HWH
6. Oil at $30.29/MWH
7. Total Fuel Inv. + Adv •. Payments
B. Times: Energy Adjustment Factor
9. At s.o.c. of Capital @ 10\
10. Other Net Current Assets & Investments
11. At s.o.c. of Capital @ 10\
12. Total Annual Capital Cost of Other Fixed Assets Depreciation ~ s.o.c. of Capital @ 10~
13. Total Annual Capital Cost of Distribution (Depreciation .;. s.o.c.)
14. Total Annual OH&A (Distribution & Other)
15. Annual Transmission Capital Cost - Current System
16. Annual Transmission O&M Cost - Current System
17. T~tal Annual Transmission Cost -Current System
18. Proportion of Current Transmission Cost for All-Thermal (if Hydro = 2x Thermal)
19. Transmission Cost -All-Thermal System
20. Total Annual Cost -All-'1 ht•t"UI·tl <iy•.l ""'
MWII
15,616,719
19,531,389
1.25067
13,814,011
71,387
.5304
Manitoba -·- S"doo
697,680
872,567.4
267,163.0
2.162.3
269,325.3
336,837.1
137,006.0
31,268.0
10,000.0
41,268.0
$000 MWII
41,182,880
32,043,494
Q.77808
33,921,759
7,261,121
33,683.7
13,700.6
15,728.2
152,942.4
83,926.9
.5499
British Columbia ·-----sooo
1,760,070
$000
1,369,475.3 1,36~~
656,046.8
219,939.4
875,986.2
681,587.3
68,158.7
197,982.0
19,798.2
146,766.2
316,026.9
193,681.2
216,242.5
8,940.£!
225,182.5
"' ·O'l " /'e~=,d\)
-
G'
t-··
Notes to Table lJ.4
Data are from Statistic$ Canada, Catalogue 157-202, 1979 unless otherwise indicated
Line No.
(1)
( 2)
( 3)
(4}-(6)
( 7)
(8)
( 9 )
(10)
( 11)
(12)
(13)
( 14)
(15~
(16~
(17)
(18)
(19)
(20)
MWH and costs from Table~ 2.1 and A.3.
MWH from Table A. 5, line 5. Costs calculated as: Costs from (1) x [MW from ( 2) + Mi~ from (1} ) •
r.·nm from ( 2) ;. MWH from ( 1) •
Values per MWH for each fuel are calculated using inventory and prepayments values obtained from Ontario Hydro Statistical Yearbook, 1979r page 30, and MWH from Table 11 (Energy Gener~ted), lines 18, 22, and 24, respectively. MWH of generation for all-thermal system from Table A.3.
(4) + (5) + (6).
(7) X (3).
(8) X 0.10.
Table 13 (Total Uti1itie~), lines 17 + 21 + 22 + 23 - 26: sxcept that for Ontario, inventory and prepayment vaiues from Ontario Hydro Statistical Yearbook; 1979, page 30, are subtracted.
( 10) X 0.1 0.
T~.ble A.1, line 62.
Tab.i..e A.l~ lif'IE! 44.
Table A.l,. line 51.
Table !-;.. :&. , line 37.
Tablt? A,l, line 45.
( 15) + (16).
Table A.S, line 13.
(17} X ( 18) •
( 2) + ( 9) + (11) + ( 12) + (13) + (14) + ( 19) .
___ ., ,.,., r
" n
i ... !
I I I
8.5
Table 8.5
Supporting Estimates for Deriving Economic Cost of All-Thermal System 1979
1. "Saleable" Energy (MWH)
2. "Losses and URaccounted for" as a Proportion of Total Supply
3. Hydro Generation as a Proportion of Total Supply
4. Estimated Loss Proportion for an All-Thermal System if Losses on Hydro = 1.5 times Loss on Thermal Generation
5. Estimated Energy Generation Required for an All-Thermal System (MWH)
6. Estimated Energy Supply Required for Saleable Energy with Current System (MWH)
7. Estimated Loss Proportion for Hydro Generation at 1.5 times Thermal Generation
8. Estimated Saleable Hydro Energy (MWH)
9. OWn-Hydro Capacity (MW)
10. Churchill Falls Capacit~ Assigned to Quebec (MW)
11. Total OWn-Generation Capacity (MW)
12. Hydro as a Proportion of Total Generation Capacity
13. Proportion of Current Transmission Cost for All-Thermal System, if Cost Per MW of Hydro Equals ~wice Cost Per M\<1 of Therma 1
,
Quebec
100,525,446
.08175
.9738
.05499
106,375,008
109,475,030
.08249
971812,791
14,182.0
4,900.0
15,437.5
.9383
. 5159
Ontario
105,056,065
.06682
.3583
.05667
111,367,247
112,578,565
.08501
36,907,860
6,786.6
25,106.3
.2703
.7872
Manitoba
18,101,301
.10916
.9815
.07322
19,531,389
20,319,363
.10983
17,753,065
3,641.1
4,113.0
.8853
.5304
British Columbia
29,324,924
.12074
.8464
.08484
33,351,823
.12726
24,626,965
6,140 .. 7
7,502.7
.8185
.5499
... 29 ...
Notes to Table s.,s .
Data are frotri Statistics Can~da v Catalogu~ 157-202, 1979 unless otherwise indicated
Line No.
{1)
( 2)
(3)
( 4)
{ 5)
( 6)
( 7)
( 8)
( 9)
This is the energy actually sold (or that could have been sold) in 1979, by the utili ties. It includes firm and secondary sales but excludes exchangesw It is calculated from Table 3 (Electric Utilities) as the sum of lines 12, 13, 16, 17, 24, 27, 28, 29, 30, 31, 32, except that for Ontario, 701,925 MWH of energy supplied to heavy water plants and ~onstruetion projE'cts are added to this total (Ontario Hydro Statistical Yearbook, 1979, p. 40). '!'his quantity C.lf energy is included as ~used in own plant~ in line 23.
(34} + (11), from Table 2 (Electric Utilities).
Table 2, line 8 +Table 3 (Electric Utilities), line 11, except that for Quebec the 35,220,760 MWH of energy purchased from Churchill Falls (Table 3 (Electric Utilities), line 12 for Newfoundland) is added to the numerator. In calculating the ratio in this mli'.'"1ner it is implicitly assumed, that for power purchased, other than that from Churchill Falls, transmission losses up to the grid of the utility are borne by the vendor, that is, for this purpose we are treating these purchases on the same basis as thermal generation by the utility.
The loss porportion for the all-thermal system is calculated by solving the following equation for L: 1. 5 x L x Hydro Generation Proportion + L x ( 1. 0 -Hydro Generation Proportion) a Loss Proportion of Current System where L = loss proportion of thermal generation 1.5 ~ the assumed ratio of total losses for hydro
relative to thermal g.eneration, Hydro generation proportion is taken from (4), and loss proportion of current system is taken from (2) Therefore, L ~ Loss proportion of current system t
[1.5 x Hydro Generation Proportion + (1.0 -Hydro Generation Proportion)].
This is the estimated energy generation required to provide the quantity of ~saleable" energy with an all-thermal system with the loss proportion estimated in (4). It is calculated as (1) + [1.0- (4)].
This is the energy supply (generation and purchases) required to provide the quantity of saleable energy with the estimated loss proportion under the current system. lt is calculated as (1) + [1.0 - (2)].
(4) X 1.5.
This is an estimate of the amount of •saleable" hydro generated by the utility under the assumption that hydro losses equal 1.5 times thermal generation losses for Quebec. The estimate includes energy purchased from Churchill Falls. It is calculated as (6) X (3) X {1.0- (7)).
Table 1, line 8.
-
it) ,., co
- jj r-, ,f ~-/ '
.-,Notes to Table '-s .. s (cont'd)
Line No.
(10)
(11)
(12)
(13)
-Capacity for Churchill Ftills from Newfoundland and La[)rador Hydro, Annual Report, 197,9, figure on p. 6. f 1roportion of capacity assigned to Quebec based on proportion"of energy sold from Table A.2, line 17.
T~ble 1~ line 13.
f(-:9) + (10)] [(10) + (11)]@ This proportion ignores the CC\pacity equivalent of purchases othec than from Churchill Falls.
This proportion is estimated as follows Let c = cost of transmission per MW of thermal
Then, under the assumption that cost for hydro = 2 x cost for thermal
[{2 X c X H) + {c X Th}] = TC
where H = Hydro generation capacity Th = Thermal generation capacity TC = Current total transmission costs
then [(2 X C X H) + (c X Th)] = TC A A A
where A = H + Th = total capacity
Let h c H = hydro as a proportion of total capacity A
t = Th = thermal as a proportion of total A capacity
Then [(2 X C X h) + (c X t)] = TC
A
multiplying by A TC
[ ( 2 X ( C X ~) X h) + ( C X A X t)) = 1 TC TC
Now let C = c x A TC
= cost per MW of thermal capacity x total capacity current total transmission cost ~
= proportion of total transmission cost for all-thermal capacity
Thus [ ( 2 X C X h) + ( C X t)) = 1
and c is obtained by solving this equation where h is taken from (12)
and t = (1 -h).
n·w·sv:i td I,,
- _j
31
E·etim~,tion of ~conomic Rent on Electricity Purchased by Quebec from Churchill Falls
Estimation of Thermal Energy Generation Required to Provide Eguiv~lent Net Energy to Quebec
1. Energy Produced at Churchill Falls
2. Transmission Losses in Labrador
3. Energy Sold to Quebec at Border
4. Energy Generated at Plant for Quebec
5. Transmission Losses in Quebec at 8%
6. Net Energy Sold to Quebec at End of Transmission Network
7. Thermal Transmission Losses at 0.5 Times Hydro
8. Thermal Energy Generation Required
Economic Cost of Thermal Power
Generation Cost
9. Capital, Operating and Maintenance Cost for Nuclear Generation @ 23.568/MWH
Fuel Inventory Cost
10. Fuel Inventory Cost @ $7.98/MWH and s.o.c. of 10%
Transmission Cost
11. Current Transmission Capital Cost Per Mile in Quebec
12. Current Transmission O&M Cost in Quebec
13. Transmission Cost in Quebec for 1780 Miles of Transmission
14. Transmission Cost for Thermal at .333 of Current Cost
15. Total cost for Thermal Generation and Transmission
MWH '
38,24~,400
649,627
35,220,760
35,870,387
2,817,661
32,403,099
1,733,644
34,136,743
$000 Mills
804,534.8
27,241.1
27.8
3.7
56,070.00
18,671.3
850,447.2
_j
32 .J
Estimation of Economic .Rent on Electric.i,ty Purchased by quebec from Churchill Falls
Economic Cost of Churchill Falls Power
16. Economic Cost of Churchill Falls Power Sold to Quebec at BOrder
17. Transmission Cost in Quebec
18. Total Economic Cost of Churchill Falls Generation and Transmission
Economic Rent Estimates
19. Economic Rent on Churchill Falls Power Sold to Quebec
20. Distribution Losses in Quebec at 2.55%
21. Net Saleable Energy From C. F. in Quebec
22. Rent on Sales of C.F. Power Sold to Quebec Per Saleable Kw~
23. Economic Rent on Quebec Hydro Generation
24. Saleable Hydro Generated in Quebec
25. Rent Per KWH of Saleable Hydro Energy Generated in Quebec
___ ,, -
MWH $000 Mills
211,279.0
56,070.0
267,349.0
583,098.2
898,129.0
31,504,970
18.508
1,291,325.7
66,307,821
19 .. 475
0
\ '
""
~ ~
H • 1\ ,,
i/
-·33 -
It ,r Not•s to Table a .. 6 !
. j.
Line. No.
(1)
(2)
( 3)
( 4)
( ~)
.. (6)
( 7)
( 8)
( 9)
(10)
( 11)
(12)
(13)
(14)
(15)
06)
( 17)
(18)
(19)
(20)
( 21)
(22)
(23)
( 24)
(25)
Figure obtained from Newfoundland and Labrador Hydro.
Measured as: Total transmission losses in Newfoundland from C.F. times percentage of sales to Quebec {(1) - Table A.2, line 16) x fTable A.2, line 17).
Table 3 (Electric Utilities) line 15.
(2) + (3).
8 per cent estimate obtained from Hydro Quebec ( 3) X • 08,
(3) - (5).
0~5 ratio of los~e$ for thermal ve~s~s Churchill Falls assymed because of .remoteness of Churehill Falls 0.5 [(2) + (5)).
(6) + (7).
Cost per MWH for nuclear f~om Tab~e 2¢ __ _ (8) x cost per MWH.
Cost per MWH from Table A.4, line 5 (8) x cost per MWH x 0.10.
Table A.l, line 4'7 ·· 17,291 miles (from 57-202~ Table 10).
Table A.l, line 45 ~ 17,291 miles (from 57~202, Table 10}.
1780 miles is estimsted lenyth of transmission lines in Quebec for Churchill Falls, in Bernard, Bridges Scott study 1780 X [(11) + (12)).
.333 ratio of thermal to Churchill Falls assumed because of remoteness of Churchill Falls.
{9) + (lO) + (14).
Table A.2, line 18.
( 13) •
(16) + (17).
(15)- (18).
2.55 per cent based on Ontario, from Ontario Hydro Statistical Yearbook, 1979, p. 41. Calculated as: Distribution Losses and Unaccounted for ~ Generated and Received. (3) X .0255.
(6) - (21).
(19) ~ ( 22).
Table 3.1, line 6 - ( 19) ....
Table A.5, line 8 ( 22) •
(24) 't (25).
_j
l !
l j:
'
' .. j>
.~··
Appendix C
Descr·iption of the Procedure to Estimate the Provincial
Distribution of the Rent on Hydroelectricity Generated
by Electric Utilities on the Basis of Consumption
-' ,,
--
It) ·CO co
.' l l
I ! !
~·
·1 ?·~
1
l ) I J 'j I
! ' l
,J v'!
I I I
- 35
~ 1. Input Data Requirements
The Following data was used 1n applying this procedure.
1) A Source Matrix (S) {22 X 22)
This matrix contains, columnwise, the proportions of the total
supply of electrical energy, for each of the following sectors,
supplied directly from these same sectors. The twenty-two
sectors identified are:
electric utilities 1n each province (10)
Churchill Falls as a separate utility (1)
industrial establishments (that generate electricity) 1n
each province (10)
- the U.S. ( 1 ) .
The source matrix used is presented 1n Appendix D, Table D.l.
2) A Production Matrix (P) (15 X 22)
This matrix g1ves, columnwise, for each of the 22 sectors above,
the proportions of total electrical energy produced by hydro ana
thermal generation. The 15 rows representing the generation types
are the following:
-
II) •CO co·
,•'
[J - 36 -
- .·,lfydr~,~ generation for electric utili ties in each province
separately including Churchill Falls as a separate utility
( 11) •
- Thermal generation by electric utili ties { l·)
-Hydro generation by industrial estabiishments (l}
- Thermal generation by industrial establishments (l)
-Generation in the U.Se (1).
The production matrix used 1s presented in Appendix D, Table D.2.
3} A Diagonal Domestic Demand Matrix (D) (22 X 22)
Each diagonal element in this matrix contains the final dom-
estic demand in MW.h for that sector. For the 10 provincial
electric utilities final domestic demand is measured as the demand
by ultimate customers within the province (excluding sales to
industrial establishments which generate electricity). For
Churchill Falls, which is taken as a supplying sector only,
demand is set at zero. For industrial establishments domestic
demand is measured as the sum of demand by ultimate customers
within the province, own use by the establishments, and sales to
other establishments which generate electricity within the
province (referred to as inter-industrial establishment sales by
Statistics Canada). Demand for the u.s. sector is set at zero.
The elements of the diagonal demand matrix used are presented in
Appendix D, Table D.3.
_j
r
I I r 1( l' l r
I l l l l !
I l !
J,
l
LO ... «)co
; £ ~,
I
I ! j l
I
:, I)
- 37 ~
4f"'~.,A ·"coo~uTfi,m ··v:e:¢tor of direct exports to the u.s. for each of the
22 se·.ctors {E) ( ~2 X 1) •
Exports f.rom the u.s. sector are set at zero. The elements of
this export vector that wero used are presented in Appendix D,
Table D. 4.
5) A diagonal matrix containing estrmates of hydro rent per kil-
owatt hour of saleable hydro for the electric utilities in each
province, including Churchill Falls as a separate sector (R}
(15 X 15).
The last four diagonal elements, corresponding to thermal
generation by electric utilities, hydro and thermal generation by
ifidustrial establishments, and generation in the u.s. are set at
zero.
The estimates for rent per kilowatthour of saleable hydro used
for Quebec, Churchill Falls, Ontario, Manitoba and B.C. were
those developed in Chapter 4. For util~ties in Newfoundland
(excluding Churchill Falls), Nova Scotia and New Brunswick the
values used were the average of the estimates for Quebec and
Manitoba derived in Chapter 4. The value for Saskatchewan was set
at the average of the values derived for Manitoba and B.C. and the
'" .:;· ~ .... ,. .. ~..._.,,.,"--'"~"···-~----~, ... ,.._ ·-··~"'""+"+ ·-·······---·-
J
·LQ CX) co
I
.. k
-' 38· -
values are· likely not highly acctJrate estimates of the rent per ,., .
kilowatthour for these provinces, it should be. recalled that the
hydro energy generated by the utilities in these other provinces
amounted to only about 7 per cent of the total hydro energy
generated by the utilities in all provinces.
The values used for rent per kilowatthour of saleable hydro ~n
the R matrix are shown in Appendix D, Table D.5.
2. Notation:
s = the Source matrix ( 22 X 22)
p = the Production matrix ( 15 X 22)
D = the diagonal Domestic Demand matrix (22 X 22)
E = the column vector of direct Exports (22 X 1)
R = the diagonal matrix of Hydro Rent per Kilowatthour of
Saleable Hydro (15 X 15)
TO = a 15 X ~2 matrix where each element is the value of hydro
rent trans.ferred from the generation type (row) to the final
demanders of each column sector.
-
-lq ""'. co"""'
- 39 -
'*i:'~'\) :•l _ , n ._ " T~ '= a .column vector of length 15 where each element is the value
of hydro rent transferred from the generation type (row) to
u.s. consumers.
U - a 22 X 22 matrix where each element is the proportion of
electricity which is supplied ultimately from each (row}
sector to final demanders of each (column) sector.
In the preliminary analysis, only the direct transfers of elec-
tricity between sectors were taken into account in determining
the value of hydro rents transferred from producers to users.
In that case (case 1):
TD1 = RPSD
is a matrix of dimension 15 X 22 which g1ves the estimates
of the transfers of hydro rent from the 11 (rows)
provincial utilities (including Churchill Falls) to the
domestic customers of the 22 (column) sectors.
TEl = RPSE
is a column vector of length 15 which gives the transfers of
hydro rent from the 11 utilities to u.s. customers.
In order to estimate the ultimate transfers, i.e., taking in
account the quantities of electricity transferred indirectly
__ ., _j
·~co co .
..
between the s:ecto~s ~· the ufmatrix must be used .instead of the s " II
~at~iXi so that in this ca~e (cas~ 2): . ,.,
TDz - RPUD
'l'E2 - RPUE
It should be noted that in either case, in order to determine
the total transfer of rent from provincial util). ties to users in
each of the provinces in the TD matrix, that the columns in this
matrix representing the utility sector and industrial establish-
ment sector for each province must be ~dded. The TD matrix thus
can be reduced to 10 non~zero columns (since the columns for
Churchill Falls and the U.S. will contain zeroes as demand for
these sectors was set at zero) and 11 rows (since the rent per
kilowatthour for the 4 rows in the R matrix which do not
represent hydro generation by provincial utilities was set equal
to zero).
The reduced matrix derived in this way from the TD2 matrix is
presented in Appendix D, Table D~8. Also shown in the column
headed by "Exports" of this table are the values of ultimate
transfers of hydro rent from each provincial utility to u.s.
consumers from column vector TE2 •
--"
.. 1 ,,
•
i . \ \
®l~@~~eitl:-''1alYl '(tiJtp$rts" .of this ·table are the values of ultimate . n
transfers of hydro ''rent. from each provincial uti~ity to u.s.
consumers from column vector TE2.
3. The Procedure for Estimating the U Matrix of Ultimate
Transfers
We now describe the procedure (and its rationale) for
determining the U matrix.
The U matrix is determined entirely from the source matrix, s.
At each stage, ].
i, of this iterative procedure a matrix M , of the
same dimension as S is created which is split into two matrices,
both of the same dimension as S - a DIRi matrix of direct trans
fers at stage i, and an INDi matrix of 1ndirect transfers at
stage i.
The indirect matrix at stage i, INDi is then operated on with
the S matrix (actually it 1s premultiplied by the s matrix) to
. h i+l . h determ1ne t e M matr1x at t e next stage.
The U matrix is calculated as the sum of the DIRi matrices for
all the stages. The procedure is such that the Mi matrices will
converge to zero. This is because the splitting of the Mi
matrices results in i . which contains elements which an IND matrlX
are less than or equal to the corresponding elements in the Mi
matrix. Thus premultiplication of the INDi matrix by S (whose i+l
columns sum to unity), will produce a matrix M whose elements i
are less than or equal to those of M •
r ' .,
---··
..
. t
I
\ i
\ 'J
..
c:_.
- 42 -
JLe~t the ope.ration f.br sp·r:'itting ·of the M.i matri.x to. derive the
., DIRi matrix be de.noted by ~I and the operation for splitting of
the Mi matrix to derive the INDi matrix be denoted by J!J1
• Then
mathematically the procedure can be represented as follows:
2) DIRi
3) INDi
i+l 4) M
-
=
~>n<Ml >
flJ (Mi) I
. " - S.IND~
5) U = ~ DIRi 1
The nature of, and rationale for, the ~D and ~I operations will
now be described.
The operations ~D and ~I to split the M1 (=S) matrix at the first
stage is slightly diffet·~nt t.han these operations at all
1 subsequent stages. In the first stage the M or S matrix is split
as follows. The DIR1
or direct matrix is simply constructed as
the diagonal elements of S~ This is because WE know, looking &t
any column of s, that the base proportion of supply ~rom any
sector to itself is the diagonal element.
l I I l I I
I l \ l
I l I
l
• y
f f' I,
:~,
'i
- 43 - t \1
-::r?~~!h"' ::cte:n>:tf;r~is~t the -i'Nb1 matrix of indirect transfeL.;S atc>~the first {. - ,·
s:~aqe is· simply constructed as the.- off-diagonal or indirect
transfers, of the S matrix.
In the next stage, the M2 matrix is constructed by premulti
plying IND1 matrix by S. The effect of this multiplication is to 1
allocate the proportions in each column of IND amongst the
supplying sectors according to the direct supply proportions of
each supplying sector as represented in the direct supply
matrix s.
The M2 (and all subsequent Mi) matrix is then split into DIR2
2 and IND as follows. We know that if the elements sd (in row s and
column d) of M2 and IND1 (recall that M2 = S.IND1 ) are both
positive then supplying sector s must be a direct supplying sector
to demanding sector d at that stage. In contrast~ if an element
sd of matrix M2 is positive, while the corresponding sd element of
I l .
ND 1s zero, that sector s must be an indirect supplying sector
to demanding sector d at that stage.
Tnus the operation ~D to derive the direct matrix DIR1+l from
. Mi+l d INDi . - 11 matr1ces an · 1s as ~o ows:
DIRi+l · sd
= Mi+l if INDi Mi+l ) 0 sd ' sd x sd
= 0, otherwise.
--··
(\ ~' ("\
..
I I
..
. . ,. \"' d . . h . d. t . INDi+l f And .tbe oper.atlOn ;,..1 to er1,v~ t e 1n 1rect rna rl.x . rom
matrices Mi+l and INDi is as follows:
0, otherwise •
Since all elements of Mi+l and INDi are greater than or equal to
zero, it follows that
The U matrix is then calculated as the sum of the DIR1 matrices
at all stages i. The procedure was stopped when all elements of
an Mi matrix were less than some arbitrarily chosen small critical
value or 10 stages had proceeded, whichever came sooner. Given
the critical value of .00001 the procedure stopped at the seventh
stage- The U matrix obtained is shown in Appendix B, Table B.6.
4. Assessing the Procedure
This procedure will now be assessed in two ways by ~xam1n1ng
some of the results. The first way is a comparison of the
ultimate flows matrix (U) with the direct flows, or source
matrix (S). For example consider the case of New Brunswick
discussed in the text of Chapter 5. The major entries for
utilities in New 9runswick (column 5) in the S and U Matrices are
compared below.
-
r I
...... ~ -L ;
Utilities - Ch.F.
N.S.
N.B.
Que.
Ind. Est. - N.B.
Que.
u .. s. -
,,
!!'!"' 4S ~
.012360
.690628
.293883
.001196
.001930
u
..092552
.011384
• 6918·05
.196600
.000480
.004700
.001948
The main effect is that the ultimate supply percentage from
Churchill Falls is about 9 per cent compared to zero in the direct
transfer matrix. A second effect, corresponding to the first, is
that the ultimate supply percentage from utilities in Quebec falls
to 19.7 per cent from 29.4 per cent in the direct transfer matrix.
A third effect is that the percentage supplied from industrial
establishments in New Brunswick falls from 0.12 per cent to
.05 per cent mainly because New Brunswick utilities provide
directly about 60 per cent of the electricity supplied to indus-
trial establishments in the province (see column 15 for industrial
establishments in New Brunswick in the S matrix, Table D.l).
Correspondingly, the percentage supplied by utilities in Ne\J
Brunswick to themselves rises in the U matrix. This percentage
rises also, while the percentage supplied from utilities in Nova
Scotia falls, because New Brunswick utilities supply about 8 per
cent of the total supply of electricity to Nova Scotian utilities
(see column 4 for electric utilities in Nova Scotia in the s
matrix, Table D.l)~
__ ,, - _j
...
. }
- 46
. · tt'hu:S:· in., this ca.$e th.e ~'"esults obtained for the U matrix can be '"" ,, .. l,
rationalized. Similarly other columns in the U matrix can be
rationalized by the pattern of direct flows in the S matrix.
A second method of assessing the procedure is a comparison of
the total ultimate supply of hydro electricity for the utilities
required to meet all the domestic demands of the 21 domestic
sectors and exports. These results are shown in Appendix D,
Table D.7 (they are calculated as the column sums of matrix BUD
plus column vector BUE) where they are compared to the actual
quantities of hydroelectricity generated by the utilities.
Since the results obtained using the procedure are demand-
driven, that is they are determined by the demand values in D and
E, there is no guarantee that the quantities of hydroelectricity
estimated to be required to meet these demands, given the 0
matrix, will not exceed the actual amounts generated. In fact we
should expect the estimated amounts required to be less than the
amounts actually generated by a percentage roughly equal to that
lost in transmission and distribution.
This is in fact what the comparison in Table D.7 reveals, so
that on the basis of this assessment also, the results appear
very reasonable •
--···
r !I
f
I • I
l l i
I
n ·CO o·
i
I I i
1
"I
l I
' . ~ I !
-;,:::-
, .. '!It! .n~h ~~'~h±,s>~regarcf, it should be noted that the proportions used for
the progu'ction matrix, P, l\Jere based on the ac.tual generation
proportions. That is, no account was taken of the fact, that on
average, because of greater losses in transmission on hydro gener-
ation, the proportion of hydro generation which ~s saleabl.e would
be lower on average than in the case of thermal generationp As a
result of this simplifying assumption used in the procedure-that
the percentages of energy lost in transmission from hydro and
thermal generation are the same - the quantities of hydro electri-
city requir-ed to meet final demand are overestimated relative to
thermal generation. As a result the hydro rents estimated using
the procedtH"'·e are some\-\.~hat higher than the estimates obtained for
Churchill Palls and the four provinces in Chapter 4, where
differential losses between hydro and thermal were taken into
account (see Table D.8 where the degree of overestimation is
shown).
---~· _j
,1
I I
·'"'
Appendix D
Supplementary Tables to Chapter 5
j• ----
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Total Supply (000' s MWH) 5,398 38,246 512 6,672 12,981 124,541 116,870 21,421 10, 3,66
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Sollrce: Statistics Canada, Electric Power Statisth:s, Volume II, Annual Statistics, 1979, Tables 3 and 7. Note that from these tables, it is possible to derive exactly the interprovincial flows of electn.r:ity between utilities and industrial establishments on a. province-to-province basis. The:se flows can be determined by multiplying the proportions in the columns of the S matrix by the t.0ta1 supply shown beneath the columns.
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D'i;agon~l Elements· of Diagonal Matrix of Domestic Final Demands (D)
Electric·· Utilities
Nf1d. Che Falls P.E.I. N.S. N.B. Que. Ont. Man. Sask. Alta. B.C.
1 2 3 4 s 6 7 8 9
10 11
(MWH)
5,117,018 0
453,339 4,950,568 5,696,964
80,734,901 85,536,526 11,137,323
7,802,438 17,308,537 24,982,758
Industrial E stab 1 i s hme n.t (MWH)
r.-;~-;.d. 12 1,869,437 PoE.I. 13 0 N.S • 14 1,210,263 NeB. 15 1,650,886 Que. 16 18,982,907 Ont. 17 10,569,227 Man. 18 676,947 Sask. 19 620,660 Alta. 2··-. . 2,001,638 B.C. 21
.~ 12,262,781 u.s. 2:t 0
Source Statistics Canada, Electric Power Statistics, Volume II, Annual Statistics, Catalogue No. 57-202 1979, Table 3. For electric utilities •. elements are: taken from line 33; for industrial establishments, elements are equal to the sum of lines 2 3 , 3 3 and 3 6 •
..
.. _,_,__,_..._..,..,.__. ____ .._,,.._. ____ ,...,........ ....... ~--..... ·~·-,.,· ~-,, ...... ~.~~·---· ~
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Table D.4
Column Vector of Exports (E)
Electric Utilities
Nfld. Ch .. Falls P .. E.I. N.S. N.B. Que. Ont. Man. Sask. Alta .. B.C.
(MWH)
1 0 2 0 3 0 4 0 5 3,596,848 6 7,662,939 7 11,891,946 8 4,080,308 9 0
10 0 11 2,4281,627
0
53
Innustrial Establishment
Nfld. 12 P.E .. I. 13 N.S. 14 N.B .. 15 Que. 16 Ont. 17 Man. 18 Sask. 19 Alta. 20 B.C .. 21 u.s. 22
Source Statistics Canada, Catalogue No. 57-202, line 19.
l. --·---"
(MWH)
0 0 0
292,730 0
301,304 0 0 0
1,123,704 0
1979, Table 3,
. .....
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Table D. 5
Diagonal Elements of Diagonal Matrix of Rent per Kilowatt Hour of Saleable Hydro (R)
Electric Utilties ( $/K"wH) Electric Utilities ($/KWH)
- Hydro - Nfld. 1 .024430 - Hydro - Sask. 9 .031322 - Ch. Falls 2 .018508 - Alta. 10 .033259 - P.E.I. 3 o.o - B.C. 11 .033259 - N.S. 4 .024450 - Thermal 12 0 - N.B. 5 .024430 Industrial Establishments - Que • 6 .019475 - Hydro 13 0 - Ont. 7 .020398 -
1rhermal 14 0 - Man. . 8 .029385 UoS. 15 0
Source Chapter 3 and text of Appendix c.
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--57
Table D .. 7
Comt,arison of Estimated Saleable Hydro and Actual Hydro Gene~ration by Provincial Utilities, 1979
Nfld.
Churchill Falls
P.E.I.
N.S.
N.B.
Que.
Ont ..
M.an.
Sasko
Alta.
B.C.
Estimated Actuall (MWH)
2,827,155 3,424,189
34,698,939 38,246,4002
0 0
1,067,837 1,136,057
2,830,614 3,071,677
68,248,799 74,649,405
37,417,516 40,411,091
17,755,699 20,443,109
2,049,440 2,330,730
1,267,705 1,415,187
25,992,456 29,747,291
Percentage Loss : (Actual-Estimated)
Estimated (per cent)
17 ll 4
9.3
6.0
7.8
8.6
7.4
13.1
12.1
10.4
12.6
1 Source Statistics Canada, Electric Power Statistics, Volume II, Annual Statistics, Catalogue No. 57-202, 1979, Table 2, line 8.
2 Unofficial estimate obtained from Newfoundland and Labrador Hydro.
-__ ,, - I
I I r
••
rable 1>.11
... ... ...
8.5 8
lsti111ated Transfers of Hydro Rents, FrOfl E1ectrtc Utilities to Users, by Province and the u.s., 1979
($000)
Users In:
Hf N.S. H. "an. Sa
lfld. 68,539.3 0.1 0.1 1.1 519.1 2.5 0.0 o.o o.o
:h. Falls 45,881.3 547.5 175.8 ll,453.3 503,518,8 25,610.3
o.o
3.6
o.o
0.3
o.o o.o
o.o o.o
o.o
69,062.2
507,790.9
o.o P.E.I.
li.S.
!1. B.
:>nt.
!tan.
Saak.
l\1ta.
B.C.
Total
o.o 0.0 o.o o.o o.o o.o
o.o
0.2
o.o 17.7 25,490.3 370.3 o.o
3.2
o.o 0.0 o.o
o.o 1,968.0
o.o 1,221.0
o.o 1.3
0.0 0,1
o.o
o.o
o.o
o.o
2,788.5 41,166.5 0.0 o.o o.o
1,730.1 25,541.8 1,122,175.8 57,112.8 8.1 0.7 o.o
1.0 26.2 1,149.0 673,31a.a 95.3 e.; o.o
0.1 1.7 73.5 43,122.7 325,285.1 29,711.7 8.1
0.0 o.o o.o
0.3
o.o
131.4 3,363.4 60,284.4 16.5
o.o 0.0 o.o o.o 41,369.2
o.o
o.o
25,878.3
45;926.4
o.o 1,207,790.3
o.o 674,601.1
0.1 398,203.1
O.J 63,816.3
723.4 42,092.6
o.o o.o o.o o.o o.o O.Ci o.o o.o 2,603.8 785,871.6 789,.t75. 4
114,420.6 3,755.7 30,786.7 78,560.9 1,627,439.7 799,l9B.7 328,775.5 9o,oo~.e 43,997.6 786,595.4 3,goJ,6JS.6
,. !If
5.3
54,417.6
o.o
208 .• 9
23,225.4
'In tal
69,067.5
642,208.5
o.o 26,087.2
69, 151.8
121,355.0 1,329,.145.3 1,291,325.7
88,641.1 763,242.2 1521~33.1
123,546.0 521~ 751.1 !.21,671~~
376.4
70.0
64,192.7
42,162.6
864,463.7
487,856.0 4,391,492.6
".~
819,019.1 5.$
------------------------------------------------------------------------------------·--------------------------------------~---- I 1 The rent on Churchill Falls production estiMated in Chapter 3 ($563.1 -illion), was only for the electricity purchased by Quebec. The corresponding estb•ate fro• this table is $596.3 million, whlch is equal to the esti111ate:d total rent on Churchill Falla' production ($642.2 ~illion} less the a111ount of rent transferred to users in L~brador ($45.9 Million).
F /(
