FRE DER I CTO N, NEW B R U Hi S W

CONFIDENTIAL TO O?%&RS OF THE GOVERNMENTS OF CANADA AfiD NEW BRUNSWICK ,&; \ ?s1 .&ti

REPORT OF THE SAINT JOHN RIVER BOARD FREDER I CTO N, NEW B R U hi S W ICK JUNE, 1960 I' September 30, 1960

The Honourable Alvin Hamilton, The Honourable Louis J. Robichaud, Minister for Northern Affairs Premier of New Brunswick, and National Resources, Fredericton, Ottawa, Ontario. New Brunswick.

Dear Sirs:

The Saint John River Board has completed the studies which were

assigned to it under the Terms of Reference, dated March 24, 1959, but modified by Governmental permission as to date of reporting, and submits herewith its report with respect thereto.

Members for the Government Members for the Government of of Canada New Brunswick

(R.H. Clark), Member, Chief Hydraulic Engineer, General Manager, Water Resources Branch, The New Brunswick Electric D epartrnent of Northern Power Comrnis sion. Affairs and National Resour c e s,

(J .$. Peter s), Member, (J. S. Bates, Ph. D., ), Member, District Engineer, Chairman, Halifax, New Brunswick Water Authority. Water Resources Branch, Depaxtment of Northern Affairs and National Res our ces. EFFECTS OF STORAGE ON POWER GENERATION IN NEW BRUNSWICK

REPORT OF THE SAINT JOHN RIVER BOARD FREDERICTON, NEW BRUNSW ICK JUNE, 1960

TERMS OF REFERENCE

WHEREAS the International Passamaquoddy Engineering Board is at present studying possible power developments and large storage reservoirs located on the upper Saint John River, as well as the effect that such a development might have on the potential power output of the proposed

Passamaquoddy Tidal Project;

WHEREAS it is desirable and in the public.interest to determine the effect on river flows, and on existing and potential power developments and on the other water uses in New Brunswick of storage possibilities in the

Saint John River basin with particular reference to storage on the upper Saint

John River and its tributaries when operated primarily for:

(a) maximum at- site power production, (b) maximum basin power production, (c) firming Pas samaquoddy tidal power output;

WHEREAS the Governments of Canada and of New Brunswick have

agreed to undertake such a study jointly;

The two governments hereby agree to the following Terms of

Reference under which this study and report shall be made:

1. The Saint John River Board (hereinafter called "The Board") is

hereby established effective August 1, 1958, the membership to be:

For Canada

(a) - Chief Hydraulic Engineer, Water Resources Branch, Department of Northern Affairs and National Resources. (vii)

(b) - District Engineer, Halifax, Water Resources Branch, Department of Northern Affairs and National Resources.

For New Brunswick

(a) - General Manager, New Brunswick Electric Power C ommis s ion.

(b) - Chairman, New Brunswick Water Authority.

2. The Chairman of the Board shall, for the .first six months, be a

member for Canada. The chairmanship shall rotate thereafter every six

months between a member for New Brunswick and a member for Canada.

3. The members of the Board shall name alternates to represent them

aad to vote for them at meetings of the Board which they cannot attend.

4. The Board shall plan, supervise, and carry out an investigation to

determine how the present and future power developments in New Brunswick

would be affected by the development and operation of storage on the upper

Saiat John River and its tributaries.

5. In carrying out this investigation the Board shall consider the com-

parative benefits to be de.rived by New Brunswick from:

(a) - the proposed integrated Passamaquoddy - Saint John River developments ;

(b) - the integrated Saint John River development with the exclusion of the tidal project should energy from tides prove too costly;

The Board shall also consider the effects of the said power developments on the other potential water uses of the Saint John River basin.

6, The Board may submit interim reports to the two governments but,

in all events, shall render a final report on its findings not later than 30 June

1960.

7. The Board shall be terminated within a period of three months from

the submission of the final report unless the governments otherwise direct.

8. Work under this reference does not include field investigations for

establishing physical aspects of existing or potential power sites in New

Brunswick.

9. Canada and New Brunswick shall share equally the cost of the said

investigation and report. They shall provide, on an equal basis, the funds

necessary for the general expenses of the Board and for the work authorized

by the Board and carried out especially in the interest of its investigation,

as distinct from work normally carried out by the departments of govern-

ment co-operating with the Board.

10. In conducting its investigations and performing its duties, the

Board may utilize the services of engineers, specialists, and other employees

of the public services of Canada and New Brunswick. It may call on govern-

ment departments to conduct studies and to provide information which may

require the formation of departmental or inter-departmental committees

The Board shall make all possible use of existing reports, information and technical data and also an: that may become availabl- during the course of its investigations, in order to avoid unnecessary expense and duplication of effort.

11. In addition to the federal and provincial employees referred to in paragraph 10 above, the Board may employ an executive officer and such engineers, specialists or other personnel as it may deem necessary and it may incur such other expenses as may be required for the purposes designated and pay for the same out of funds appropriated therefor.

Signed this 24th day of March 1959, in the presence of: on behalf of the Government of Canada

D. J. Thiessen Alvin Hamilton

M.inister of Northern Affairs and National Resources in the presence of: on behalf of the Government of New Brunswick

K.B. Carson Hugh John Flemming

Premier . BOARD MEMBERSHIP

MEMBERS AND ALTERNATES

For Canada:

R.H. Clark, Member, W V. Morris, Alternate Member , Chief Hydraulic Engineer, Hydraulic Engineer, Water Resources Branch, Water Resources Branch, Department of Northern Affairs Department of Northern Affairs and National Resources. and National Resources.

JOE.Peters, Member, D. F. Kirk, Alternate Member, District Engineer, Engineer, Halifax, Halifax, Water Resources Branch, Water Resources Branch, Department of Northern Affairs Department of Northern Affair s and National R e sources and National Resources.

For New Brunswick

R, E. Tweeddale, Member , G.H.D. Ganong, Alternate Member, General Manager, Engineer in Charge Hydraulic The New Brunswick Electric Production, Power Commission. The New Brunswick Electric Power Commission.

J. S. Bates, Ph.D., Member, A. 3. O'Connor, Alternate Member, Chairman, Manager of Engineering, New Brunswick Water Authority. The New Brunswick Electric Power Commission. ACKNOWLEDGMENTS

The Board wishes to acknowledge the valuable co-operation of the Water Resources Branch, Department of Northern Affairs and National

Resources, Canada, The New Brunswick Electric Power Cornmission, The

Nova Scotia Power Commission, the Nova Scotia Light & Power Company

Limited, and the many federal and provincial government departments, and private agencies which provided information, reports, and technical data that have been essential to the completion of the Board's report.-

The Board extends its thanks to its Executive Engineer, Dr. A. F.

Baird, P. Eng., who co-ordinated the studies and reports of the various agencies and the Board's engineering consultants.

The engineering studies were carried out by H. GoAcres &z Company

Limited, Consulting Engineers, Niagara Falls, Ontario, with the firm of

H. S. Gellman and Company Limited, Data Processing Consultants, Toronto,

Ontario. The Board wishes to make special recognition of the services of

Mr. R,L. Clinch, P. Eng. , Executive Engineer, H.G. Acres & Company

Limited who guided the technical aspects of the study and report throughout,

and to Mr. HOE.Marshall, P. Eng., System Planning Engineer, The New

Brunswick Electric Power Commission. (xii)

TABLEOFCONTENTS

-Page LETTER OF TRANSMITTAL...... (ii)

FRONTISPIECE ...... (iv)

TERMS OF REFERENCE . e e *. a a (vi)-(ix)

BOARD MEMBERSHIP...... ( x)

ACKNOWLEDGMENTS...... (xi)

TABLE OF CONTENTS *. *. . D. . D. e *. a .. (xii)-(xiii)

LIST OF PLATES...... i ...... (xxi)-(xxii) APPENDIX ...... (xxiii)

SECTION 1 - INTRODUCTION...... 1 1.1 .Purpose of Study ...... 1 1.2 - Scope of Study . e e ...... e . e 2

SECTION 2 - STORAGE IN THE SAINT JOHN RIVER BASIN...... 10 2.1 - Existing Storages e e *,. e e *. -. 12 2.2 - Potential Storage on the Saint .JohnRiver e . . . 12 2. 3 - Potential Storages on Tributaries of the Saint John River ...... 15

SECTION 3 - NEW BRUNSWICK ELECTRIC UTILITIES e 20 3.1 - Definitions ...... 23 3.2 - Load Growth ...... 25 3.3 - Hydro-Electric Generation . . *.. -.a -. e 33 3.4 - Thermal-Electric Generation ...... 45 3.5 - GenerationCosts...... 47

SECTION 4 - NOVA SCOTIA ELECTRIC UTILITIES .INTERCONNECTED WITH NEW BRUNSWICK 62 4.1 - Generation...... 63 4.2 - Load Growth ...... 70 (xiii)

l Page \-

SECTION 5 - TRANSMISSION e. *.. . m. -.. e *. . . . . *. . e. -. 72 5. 1 - Network Analyzer Study . -. *. . #...... e D.. 72 5.2 - Costs...... 76

SECTION 6 - THE PASSAMAQUODDY TIDAL POWER PROJECT 80

SECTION 7 - SYSTEM STUDY PROCEDURES . . . e e e 86 7.1 - Scope .~OO.DDOOOOO..~OOOO...~~~~~**~~.*~~~~~~.~86 7.2 - System Operating Criteria o.. .e e e *.. . a 90 7.3 - Input Data. *. . . *...... *. o.. . . a e. Do e *. . *. D. a 98 7.4 - Output Data oo a e *. . ,*. . eo Do 104 7.5 - Simplified Flow Charts -.e *. e 107

SECTION 8 - SEQUENCES OF DEVELOPMENT a e. e a e 112 8-1 - Case I Sequence - The New Brunswick Electric

Power Commission System Only . -.. . . e D.. 117 8.2 - Case I1 Sequence - Effect of Interconnection with Nova Scotia.. . . *...... *. . . . e. -.*. a a *. *. 123 8.3 - Case I11 Sequences -Effect of Rankin Rapids Storage and Power Development. e . . 126 8.4 - Case IV Sequences - Effect of Passamaquoddy and the Rankin Rapids Storage and Power Development 142

SECTION 9 - COMPARISON OF SEQUENCES a D.. -.. #. . . e a 151

SECTION 10 - EFFECTS ON OTHER WATER USES *. . #. . D.. . 169

10.1 - Introduction.. . D...... m...... e.o. o. 169 10.2 - Water Quality.. . Dee .. . . *...... , e *..D.. . e a 171

10. 3 - Recreation.. . *.. . #. *. . . D. a -... *...... D. 175

10.4 - Fish ....oO..D....a..O DO...... D...OD 178

10.5 - Wildlife e D. *. . . *.. e *. *. . a -.. . -.. . . . -.. 180 10.6 - Navigation *. *. *. . D. -.. *. . a eo a. 182

10.7 - Log Driving -. . e a D, a *. . . e . a *. . . e . e 183

10.8 - Summary ooo .. .o. 0...... -**.. .oo ...... 184

SECTION 11 - FINDINGS . . . . *. *. #. . . . . , . @. e. *. . a -.#. 186 (xiv) . .

LIST OF TABLES

- Number Title Page

1 Existing Storages on Tributaries of the Saint John River...... *...... 10

2 Potential Storages in the Saint John River Basin ...... 11

3 Potential Storages on Tributaries of the Saint John River - Approximate Costs of Stored Energy ...... 18

4 Industrial and Utility Generation in New Brunswickl959 ...... 21

5 Existing Hydro-Electric Developments on the Saint John River and its Tributaries in New Brunswick...... 22

6 Distribution of Energy Demand by Class of Service .1959 .N. l3. E. P, C. System ...... 26

7 Average Annual Amount of Energy Sold Directly to Domestic and Commercial Consumers - N. B. E. P. C.. System ...... 28

8 Monthly Firm Power and Energy Demand Factors (Effect of Load Growth Removed) - N. B. E, P. C. System...... 31

9 Estimated Future Distribution of Firm Load Demand iil Megawatts - N6 BeE. P. C, System . 32

10 Capacity of Existing Hydro-Electric Plants

in December 1959 - N. B. E, P. C,. System D.. 3 6

11 Musquash Development - Mean Monthly Energy outputs ...... 35

12 Milltown Development - Mean Monthly Energy Outputs ...... 36 Number Title Page

13 Potential Capacity at Undeveloped Hydro- Electric Sites on the Saint John Eiver in New Brunswick Above Tidehead . . . * . . 39

14 Potential Capacity at Developed Hydro- Electric Sites on the Saint John River * - - a + * a * . * 40

15 5 Per Cent Probability Fall Floods at Existing and Potential Power Developments

on the Saint John and Tobique Rivers e . a e . e 42

16 Pandage at Existing and Potential Power Developments on the Saint John and Tobique

Rivers .OD..O.O DO O..OOO O....a...O. .. 43

17 Assumed Percentage Reductions in Head Due

to Forebay Drawdown -.e a. a e e e e 44

18 Nameplate Rating and Net Capability of Existing Thermal-Electric Plants. - 1959 N. B, E. P. C. System, ...... a ...... 46

19 Nameplate Rating and Net Generating Capability of Typical Modern Thermal-Electric Units ...... ~~ 47

20 Estimated Capital Costs for Potential Hydro- Electric Developments on the Saint John River * . 49

21 Estimated Capital Costs of Extensions at Developed Hydro-Electric Sites on the Saint JohnRiver...... o...... 50

22 Estimated Capital Costs of Typical Modern Thermal-Electric Units in New Bxunswick . . *. 50

23 Estimated Operation and Maintenance Charges for Potential Hydro-Electric Developments on

the Saint John River . . e e e e -.., 53

24 Estimated Operation and Maintenance Charges for Extension to Existing Hydro-Electric

Developments on the Saint John River . D. *. e 54 (xvi)

Number Title Page

25 Operation and Maintenance Charges for Typical Modern Thermal- Electric Generating

Stations in New Brunswick.. . . *. e a -.. . . e 55

26 Fuel Costs for Typical Modern.Therma1-' Electric Stations in New Brunswick. . . 56

27 Annual Charges for Potential Hydro-Electric

Developments on the Saint John River o. . a a *. . 58

28 Annual Charges for Extensions to Existing Hydro-Electric Developments on the Saint JohnR~ver...... 59

29 Fixed Annual Charges for New Thermal- Electric Units in New Brunswick . a . . - 60

30 Variable Annual Charges for New Thermal-

Electric Units in New Brunswick # D. o. - * * . 61

31 ,Nameplate Rating and Maximum Two-Hour Gross Capability - The Nova Scotia Power

Commission System - 1959 e a D. e . 64

32 Nameplate Rating and Maximum Two-Hour Capability - Nova Scotia Light & Power Company Limited System - 1959 -.*. 67

33 Summary of Nameplate Ratings of Generating Stations - The Nova Scotia Power Commission and Nova Scotia Light & Power Company

Limited Systems - 1959 a e . 68

34 Assumed Monthly Demand Factors for the

Nova Scotia Interconnected Load.. a s. 71

35 Sequence of Development III(c) -. m. 74

36 Capital Costs of Transmission and Terminal Facilities irr New Brunswick e - *. 76

.. (xvii)

Number Title Page

37 Annual Operation and Maintenance Charges - Transmission Lines - N. B. E. P. C. System . -.. 77

38 Annual Operation and Maintenance Charges - Terminal Facilities - N, B. E. P. C. System e . e . 78

39 Annual Charges for Transmission and Terminal

Facilities in Sequence III(c) *. *. *. a a o., . *, . . 79

40 Mean Monthly Energy Outputs - Pas samaquoddy Tidal Power Project . . . . . e *. . . o. *. . . 82

41 Variation in Energy Output - Passamaquoddy Tidal Power Project *. . . *.. =. *. . . , . *. . e.. 83

42 Low April Flows at Pokiok Gauge, with Flows for the Preceding March, Selected from the

Period 1932 to 1952 *. . . . -.e #. . . -.. . *. . 91

43 Minimum Accumulated Natural Flows at the PokiokGauge ...... 93

44 Natural Mean Monthly Flows at all Gauges for the Artificial Year as Used in the Rule Curve

Calculation ~...~.OO...OO..O~....~~.~..~~~~~~94

45 Input Data - System Load Characteristics 99

46 Input ,Data - Generating Station and Storage Reservoir Characteristics -.. *. e *. . *. e 100

47 Input Data - River Flow Records and Drainage

Area Ratios. e o. m.. *.. a. o. a a a e a e 102

48 Input Data - Operating Rules. *.. . . *. . . . D.. 103

49 Input Data - Cost Information . . e e e *. . , e D. 103

50 Output Data - Annual Average, Minimum, and Maximum Values for the 240-Month Period. *. . 105 (xviii)

Number Title Page

51 Output Data - Monthly Values for the 240-

Month Period oo *. . e D.. . e *. D. o. *. e 106

52 Case I - Average Annual Energy Generation and Costs in New Brunswick e e -. a e s. 121

53 Comparison Between Costs of Hydro-Electric Generation on the Saint John River and the Costs of Equivalent Thermal Generation - Case I

Sequence - Year 1980 ... e.o a a.m a O.D.D e 122

54 Case I1 - Average Annual Energy Generation and

Costs in New Brunswick and Nova Scotia e D.. -. 127

55 Comparison Between Costs of Hydro-Electric Generation on the Saint John River and the Costs of Equivalent Thermal Generation - Case II

Sequence - Year 1980 ..O...... D.D.~.O..O..D.. 128

5.6 Assumed Monthly Demand Factors for a Utility Load ~Maine...... 130

57 Case III(a) - Average Annual Energy Generation and Costs in New Brunswick and Nova Scotia 1.33

58 Comparison Between Costs of Hydro-Electric Generation on the Saint John River and the Costs of Equivalent Thermal Generation - Case III(a)

Sequence - Year 1980 O..~O.O.O.D..DDD..~O.D.. 134

59 Case III(b) - Average Annual Energy Generation

and Costs in New Brunswick and Nova Scotia e *. 137

60 Comparison Between Costs of Hydro-Electric Generation on the Saint John River and the Costs of Equivalent. Thermal Generation - Case Iii(b)

Sequence -Year 1980 ., e O.D.O ..D.O.. 138

61 Case IIIQc)- Average Annual Energy Generation

and Costs in New Brunswick and Nova Scotia e a a 140 (xix)

Number Title Page

62 Comparison Between Costs of Hydro-Electric Generation on the Saint John River and the Costs of Equivalent Thermal Generation -

Case III(c) Sequence - Year 1980 e -. e e *. ., 141

63 Case IV(a) - Average Annual Energy Generation.

and Costs in New Brunswick and Nova Scotia ~ ~ 144

64 Comparison Between Costs of Hydro-Electric Generation on the Saint John River and the Costs of Equivalent Thermal Generation - Case IVQa) Sequence - Year 1980 . e *. 145

65 Case IV(b) - Average Annual Energy Generation and Costs in New Brunswick and Nova Scotia 146

66 Comparison Between Costs of Hydro-Electric Generation on the Saint John River and the Costs of Equivalent Thermal Generation -

Case IV(b) Sequence - Year 1980 #. e -,. 147

67 Case IV(c) - Average Annual Energy Generation and Costs in New Brunswick and Nova Scotia 148

68 Comparison Be tween Costs of Hydro-Electric Generation on the Saint John River and the Costs of Equivalent Thermal Generation - Case IV(c) Sequence - Year 1980 *. -. -.. . 149

69 Comparison of System Costs in New Brunswick and Nova Scotia for Case 1 and Case I1

Sequences a O.O a Do a.a ..D a oe a 150

70 Comparison of 1980 Costs for the Mactaquac Development in Cases 11, 111, and IV Sequences - 8 Units - 414 Megawatts Net Capability, *. . 155

71 Comparison of 1980 Costs for the Grand Falls Extension in Cases 11, 111, and IV Sequences -

6 Units - 229 Megawatts Net Capability . a o. . . 155 Number Title Page

72 Comparison of System Costs in New Brunswick

and Nova Scotia for Cases 11, III(a) and III(b). a , 167

73 Comparison of System Costs in New Brunswick and Nova Scotia for Cases 11, IV(a) and IV(b). 167

74 Revised Energy Figures for Case III(b) Sequence

with Morrill Development Excluded. e . e e . . . . 160

75 Summary of Total Benefits Attributable to the

Rankin Rapids Development a a * . . . e e. 162

76 Comparison of System Costs in New Brunswick

and Nova Scotia for Cases III(b) and III(c) . . . . a 163

77 Comparison of System Costs in New Brunswick

and Nova Scotia for Cases IV(b) and IV(c) -.. e . . 164 LIST OF PLATES

Number Title 1 Saint John River Basin - Existing and Potential Storages

2 Saint John River - Typical Modifying Effect of Rankin Rapids Storage and Existing Storages

3 Load Growth of New Brunswick Electric Power Commission System

4 Monthly Load Duration Curve - NeBo E. P. C. System

5 Variable Annual Charges for Existing Thermal- Electric Stations - N. B, E. P. C. System

6 Assumed Monthly Load Duration Curve - Nova Scotia Interconnected Load

7 N. B. E. PoC. System in 1960

8 Probable N. B, E. P. C. System in 1963 - Case III(c) Sequence

9 Probable N. B. E. P. C. System in 1968 - Case III(c) Sequence

10 Probable N. B. E. P. C. System in 1974 - Case III(c) Sequence

11 Probable N. BoE. P. C. System in 1980 - Case III(c) Sequence

12 Typical Rule Curve for Control of Storages

13 Computer Program - Simplified Flow Charts

14 Illustrations of Power and Energy Computations

15 Sequences of Development - Generation and Costs - Case I (xxii)

- Number Title 16 Sequences of Development - Schematic Index - Case I

17 Sequences of Development - Generation and Costs - Case I1

18 Sequences of Development - Schematic index - Case I1

19 Assumed Monthly Load Duration Curve for a Utility in Maine.

20 Rankin Rapids Development - Potential Average At-Site Energy - Cases III(a) and III(b)

21 Sequences of Development - Generation and Costs - Case III(a)

22 Sequences of Development - Generation and Costs - Case IIII(b)

23 Sequences of Development - Schematic Index - Case III(b)

24 Sequences of Development - Generation and Costs - Case III(c)

25 Rankin Rapids Development - Hydrographs of Natural and Controlled Flows - Case III

26 Rankin Rapids Development - Potential Average At-Site Energy - Cases IV(a) and IV(b)

27 Rankin Rapids Development - Hydrographs of Natural and Controlled Flows - Case IV

28 Sequences of Development - Generation and Costs - Case IV(a)

29 Sequences of Development - Generation and Costs - Case IV(b)

30 Sequences of Development - Generation and Costs - Case IYgc) (xxiii)

APPENDIX

For convenience of reference much of the basic data related to the Saint John River and its tributaries is presented in an appendix en- titled: "SAINT JOHN RIVER - CHARACTERISTICS AND WATER USES''.

This appendix gives a description of the characteristics of the Saint John River and its drainage basin, and details of existing and potential storage and hydro-electric developments. It also contains copies of reports, memoranda and letters submitted to the Board dealing with the possible effects of increased utilization of the hydro-electric potential of the river and of its tributaries on other water uses. -1-

1 - INTRODUCTION

1.1 - Purpose of Study

The hydro-electric potential of the Saint John River and its tributaries in the Province of New Brunswick has been found to be of the order of

one million kilowatts with an average annual energy output of over three billion kilowatthour s. The development of storage upstream could have significant

effects on the energy output and the sequence of development of this potential.

It was primarily to study these effects that the Saint John River Board was

established.

The greatest amount of live storage which can economically be developed at a single site is 2, 800, 000 acre-feet at the proposed Rankin Rapids

power development in the State of Maine. The benefits which could be obtained

by integrated operation of this development with existing and potential power

developments on the Saint John River in New Brunswick, is another aspect

which was studied.

The construction and operation of additional power developments

on the Saint John River in New Brunswick and the development of additional

storage upstream will affect other water uses of the river. Some of these

effects can be estimated only after detailed study by the various agencies con-

cerned. Within the time limits set by the Terms of Reference, it has only

been possible for the Board to record available information and opinions and

to outline those problems requiring further study. -2-

1. 2 - Scope of Study

The most satisfactory method of evaluating the effects of upstream storage onpresent and future power generation in the Province of New Brunswick is to compare the probable sequences of power development in the province, with andwithout storage. By this means, it is possible to estimate the actual effects onpower generation in terms ofboth energyandmoney. However, studies of this type are inherently complex andbefore presenting the details and conclusions which were reached, the initial approach which was taken by the Board, and whichledto the choice of various basic conditions for the sequences whichwere

compared, is described.

The scope of the studies carried out by the Saint JohnRiver Board was governed primarily by Clauses 4 and 5 of the Terms of Reference and

these clauses are again quoted for convenience of reference:

"4. The Board shall plan, supervise, and carry out an investigation to determine how the present and future power developments in New Brunswick would be affected by the development and operation of storage on the upper Saint John River and its tributaries.

"5. In carrying out this investigation, the Board shall consider the comparative benefits to be derived by New Brunswick from:

(a) - the proposed integrated Passamaquoddy- Saint John River developments;

(b) - the integrated Saint John River development with the exclusion of the tidal power project should energy from tides prove too costly; -3-

"The Board shall also consider the effects of the said power developments on the other potential water uses of the Saint John River Basin.

A necessary preliminary to the work described in Clause 4 is the determination of the probable pattern of future power development in the Province of New Brunswick and, in particular, the probable sequence in which the undeveloped power potential of the Saint John River will be utilized if upstream storage is not developed.

In its interim report to the International Joint Commission dated

April 1953, the International Saint John River Engineering Board described a number of possible sites for hydro-electric developments on the Saint John

River in New Brunswick and gave preliminary estimates of capital cost and power potential. These estimates were based upon limited field investigations and studies. As a first step in the work of the Saint John River Board, it was necessary to prepare detailed cost estimates for comparison with the cost of alternative power sources. Existing developments on the Saint John River in

New Brunswick and on the Tobique River have an installed capacity of 155 megawatts, and the undeveloped economic potential is now estimated to be approximately 85 0 megawatts.

The schedule for developing this power potential without upstream storage is governed by the amount of thermal power available on the system -4-

for base loading at times of low river flow. Part of the thermal power necessary

for this purpose could be made available in Nova Scotia as a result of the Inter-

connection Agreement between utilities in the two provinces which makes pro-

vision for energy interchange in the future. The extent of this interchange is

not yet defined and, for this reason, two possible conditions were studied by the

Board.

The first condition involves use of the interconnecting transmission

facilities between New Brunswick and Nova Scotia for the sharing of spare

. capacity and spinning reserve only. In the second condition, it is assumed

that energy will be interchanged to give the lowest costs on all systems.

By approaching the problem in this manner, the Board established

two possible sequences of future power development in New Brunswick with-

out upstream storage on the Saint John River. It was found that the difference

between the two sequences was comparatively small in that, in both cases,

practically the entire undeveloped potential of the Saint John River in New

Brunswick could be utilized over the next 20 years. It was therefore con-

sidered unnecessary to examine, for both sequences, the effects of the de-

velopment and operation of upstream storage on the Saint John River, and the

sequence involving energy interchange between New Brunswick and Nova

Scotia to give the maximum economy was chosen as the basis for comparison.

Specific conditions for which the effects of upstream storage on

present and future power developments in New Brunswick were to be deter-

mined, are listed in Clause 5 of the Terms of Reference. Condition (a) -5-

refers to the Passamaquoddy Tidal Power Project and Auxiliary, for which estimated costs wer.e not available when the Saint John River Board was

established. Subsequently, these figures were presented in the report to the

International Joint Commission by the International Pas samaquoddy Engineering

Board, dated October 1959.

Conclusion 12 of that report states:

"Assuming an equal division of power output and fixed cost between the United States and Canada, construction of the Tidal Power Project with all of Rankin Rapids as auxiliary, is not an economically justified project for Canada. *I

Figures of energy cost and benefit-cost ratio, in support of the

above statement, are given in Conclusion 8 of the International Passamaquoddy

Engineering Board report. Energy costs in Canada for the Tidal Project alone

are stated to be 14. 9 mills per kilowatthour with a benefit-cost ratio of 0. 34,

assuming a 50-year amortization period. Corresponding figures for the Tidal

Project with all of Rankin Rapids as auxiliary are 11. 5 mills per kilowatt-

hour for energy, with a benefit-cost ratio of 0.58. It should be noted that the

above figures take into account downstream benefits at existing developments

and were computed assuming an equal division of power output and first cost

by the United States and Canada; an interest rate in Canada of 4-1/8 per cent

was assumed.

When this information became available to the Board, it was con-

sidered unnecessary to give further study to the proposal in which the -6-

Passamaquoddy Tidal Power Project and the Rankin Rapids Auxiliary are constructed jointly by Canada and the United States.

On the other hand the International Pas sarnaquoddy Engineering

Board concluded that the Tidal Project with the Rankin Rapids Auxiliary is economically justified -if built entirely by the United States at an interest rate of 2-112 per cent. In view of this, it was considered desirable to determine the effects on future power developments in New Brunswick should the Tidal

Project and Auxiliary be constructed by the United States. For the purpose of this study it was assumed that the energy and power output would beutilized entirely within the State of Maine. In all sequences which include the Rankin

Rapids development and the Tidal Project, commissioning dates of 1968 and

1970, respectively, were assumed.

Because power and energy from the Tidal Project and Auxiliary

is not economic in Canada at the present time, Clause 5(b) of the Terms of

Reference requires that the effects of developing and operating storage at

Rankin Rapids alone be determined. For this condition, it was assumed that

the power installation at the Rankin Rapids development would be 200 megawatts as considered by the International Passarnaquoddy Engineering Board.

Finally the Board was required by Clause 5(c) of the Terms of

Reference to study the effect of possible further interconnection and pool

operation with adjoining transmission systems If the Rankin Rapids develop-

ment is constructed either with, or without, the Tidal Project, benefits can -7-

be obtained by integrated operation and flow control on the Saint John River and the seasonal exchange of energy between New Brunswick and Maine over interconnecting transmission lines. The possible extent of such benefits was determined in the studies.

The manner in which the Saint John River Board has interpreted those parts of the Terms of Reference related to power generation may now

conveniently be summarized by listing the sequences of power development in

New Brunswick which were studied in detail, and which were compared to

determine the effects, in terms of both energy and money, of developing up-

stream storage on the Saint John River.

Case I

A sequence of development in New Brunswick without Rankin Rapids storage, in which the transmission interconnection between New Brunswick and Nova Scotia is used only for the sharing of spar e capacity and spinning reserve

Case I1

A sequence of development in New Brunswick without Rankin Rapids storage, in which the transmission interconnection between New Brunswick and Nova Scotia is used for the sharing of spare capacity and spinning reserve, and for the transfer of energy to give the maximum economy in power generation in both provinces.

Cases I and I1 represent possible alternative sequences of power

development in New Brunswick without upstream storage. The cost differences

between them are small and Case I1 sequence was chosen as the base for eval-

uating the effects associated with the development and operation of storage on

the upper Saint John River. -8-

Case 111 .

Sequences in which the Rankin Rapids storage and power development is brought into operation in 1968 at 200 megawatts. The alternatives which were studied are as follows:

(a) - A sequence of development in New Brunswick identical with that in Case 11; the Rankin Rapids storage and power development is operated to meet a load in Maine.

(b) - A modification of the sequence of development in Case 11, to give improved economy in New Brunswick; the Rankin Rapids storage and power development is operated to meet a load in Maine.

(c) - A sequence of development in New Brunswick identical with that in Case 111(b)9but with the Rankin Rapids storage and power development operated integrally with generation in New Brunswick and Nova Scotia to meet the combined New Brunswick-Nova Scotia loads and a load in Maine.

Case IV

Sequences in which the Rankin Rapids storage and power development is brought into operation in 1968 at 200 megawatts, increasing to 460 megawatts in 1970 coincident with the commissioning of the Passamaquoday Tidal' Power Project,

(a) -A sequence of development in New Brunswick identical with that in Case 11; the Rankin Rapids storage and power development is operated in conjunction with the Pas samaquoddy Tidal Power Project to meet a load in Maine.

(b) -A modification of the sequence of development of Case 11, to give improved economy in New Brunswick; the Rankin Rapids storage and power development is operated in conjunction with the Passamaquoddy Tidal Power Project to meet a load in Maine. (c) - A sequence of development in New Brunswick identical with that in Case IV(b), but with the Rankin Rapids storage and power development and the Passamaquoddy Tidal Power Project operated integrally with generation in New Brunswick and Nova Scotia to meet the combined New Brunswick-Nova Scotia loads and a load in Maine.

Major uses of the Saint John River for purposes other than power generation, as referred to in Clause 5 of the Terms of Reference, are navigation (including log driving), water supply, waste disposal, fishing, and recreation. Some, if not all, of these uses, as well as pollution and flooding, will be affected either beneficially or detrimentally by the construction of additional generating stations on the Saint John River, and agencies involved in these fields were consulted. Relevant information which has been gathered is presented in this report, and problems requiring further study are outlined. - 10 -

2 - STORAGE IN THE SAINT JOHN RIVER BASIN

The International Saint John River Engineering Board report dated

April 6, 1953, contains results of a comprehensive investigation and study of

storage possibilities in the Saint John River basin, and provided a sound basis

for the studies reported herein.

The locations of potential storage sites considered by the International

Saint JohnRiver Engineering Boardare shown onplate 1, together with anumber of

other sites which have subsequently been investigated either by The New Brunswick

Electric Power Commission or by the InternationalPassarnaquoddyEngineering

Bo.ard. Existing storages, all located on tributaries of the Saint JohnRiver, are

listed in Table 1, andpotential storages for which detailed information is available,

are listed in Table 2. Pnview of the comprehensive nature of previous work,

additional field investigation of potential storage sites was not considerednecessary.

TABLE 1

EXISTING STORAGES ON TRIBUTARIES OF THE SAINT JOHN RIVER

Live Storage Volume Name Tributary Acre-Feet Temiscouata Lake M adawa s ka 105, 000 Fir st Green Lake Green 17,000 Millinocket Lake Aroostook 23, 100 Squapan Lake Aroo s took 58, 600 Trousers Lake T obique 36, 600 Long Lake T obique 28, 300 Serpentine Lake T obique 25, 600 Sisson Reservoir T obique 97,000

Total live storage in

existing reservoirs D.. . . *. , *. *, . -.. , . . . . . o., . . . . 391, 200 - 11 -

TABLE 2

POTENTIAL STORAGES IN THE SAINT JOHN RIVER BASIN

Name of Live Storage Volume Development River Location Acre -Feet

Storages on the Saint John River

Rankin Rapids Saint John Maine 2,800,000 Big Rapids Saint John Maine 1,540, 000-/I. Lincoln School Saint John Maine 22,500/_1

Maximum potential live storage . . . . a , ...... 2, 800, 0.00

-/1 The Big Rapids and Lincoln School developments are an alternative to the Rankin Rapids development.

Storages on Tributaries of the Saint John River

Daaquam River Daaquam Quebec ' 116, 000 Lac Squatec Squatec Quebec 133,500 Long Lake Cabano Quebec 34,400 Temiscouata Lake Madawaska Quebec 429, OOOG Jerry Lake Baker Brook Quebec 63, 000 Touladi Lake T ouladi Quebec 100,000 Ledges Tobique New Brunswick 195,000 Glazier Lake St. Francis International 333,000 Lac de L'Est Chimentic ook International 56,600 Boundary Lake St. Francis . International 30,000 Masar dis Ar oo sto ok Maine 535,000 Eagle Lake Fish Maine 65,000 St. Froid Lake Fish Maine 115,000 . Fish River Lake Fish Maine 124, 000 Twelve Mile Machias Maine 170, 000

Total potential live storage on tributaries . . . . D.. *. . . . 2,499,500

-/2 This potential is in addition to the present storage of 105, 000 acre-feet. - 12 -

2. 1 - Existing Storages

Existing storages inthe SaintJohnRiver basin are operated primarily to increase the winter flows at hydro-electric stations on the river or its tributaries. Storages on the Green and Aroostook Rivers are operatedfor the benefit of small hydro-electric developments at Second Falls on the Green River, and at Squapan, Caribou, and Tinker Falls on the Aroostook River or its tributaries.

They consequently provide a small measure of flow regulation at the Beechwood development. Storage on the Madawaska River affects river flow at Grand Falls and Beechwood, and storage on the Tobique River provides limited flow regulation at both the Tobique and Beechwood developments.

The existing storages listed in Table 1 have a total live storage capacity of 391,200 acre-feet and give a moderate low flow increase. During the driest period of record, natural flows at the Beechwood site for the months

of January, February, and March, averaged 3, 050 cfs. By utilizing the entire volume of live storage at present available, this average could have been in-

creased by 2, 170 cfs. Alternatively, if existing life storage had been emptied

over a six-month period from October to March inclusive, covering the period

of peak demand on the system of The New Brunswick Electric Power Commission,

the average natural flow during these six months of the driest period of record,

namely 3,830 cfs could have been increased by 1, 083 cfs.

2. 2 - Potential Storage on the Saint John River - ~ ~

The greatest single volume of live storage which canbe economically

developed on the main stem of the Saint John River is 2. 8 million acre-feet and - 13 -

is associated with the Rankin Rapids site located about 3-1/2 miles upstream from St. Francis in Maine. At this site, an earth embankment 333 feet high and 7, 400 feet long can be constructed to impound a total storage of 8. 23million acre-feet, including the live storage capacity of 2. 8 million acre-feet which is obtainable in a 35-foot drawdown. The layout of the development, as envisaged by the International Passamaquoddy Engineering Board, includes a powerhouse containing eight generating units rated at 50 megawatts each and designed to operate at 15 per cent overload. The dependable capacity of the development is given as 460 megawatts at the minimum net head of 269 feet with full turbine gate opening.

The dependable capacity of 460 megawatts was selected by the

International Passamaquoddy Engineering Board to utilize river flow at the

site for energy production, and to firm up the output fromtheproposed

Passamaquoddy Tidal Power Project. It was envisaged that if the Tidal

Project is not built, the installation at the Rankin Rapids development would

be of the order of 200 megawatts.

Construction of the Rankin Rapids development will involve flooding

of the lower reach of the Allagash River and has been opposed by some people

interested in the preservation of fishing and white water canoeing in this area.

Accordingly, the International Passamaquoddy Engineering Board considered

an alternative scheme involving a high-head darn at Big Rapids, located on

the Saint John River upstream from the mouth of the Allagash River, and a

low-head dam at the Lincoln School site, located a short distance downstream

from the Rankin Rapids site. - 14 -

The layout for the Big Rapids. development as proposed by the

International Passarnaquoddy Engineering Board is in' general similar.to that for Rankin Rapids. The total storage capacity of the reservoir would be 3. 97 million acre-feet of which 1.54 million acre-feet would be live storage obtainable in a 35-foot drawdown. The total dependable capacity of the power station would be 338 megawatts when operating at the minimum net head of 233 feet with full turbine gate opening .

,, ,, The live storage capacity of the Lincoln School development, amounting to 22, 000 acre-feet, is too small for seasonal flow regulation and would be utilized for pondage and, possibly, to give a degree of regulation to daily flows during periods of peak load operation at the Big Rapids development. The proposed dependable capacity for the Lincoln School development is 54 megawatts at the minimum net head of 81 feet,

The Rankin Rapids development was selected by the International

Passamaquoddy Engineering Board as the most favourable auxiliary to the

Tidal Project on the basis of its greater drainage area, larger storage and lower unit cost. The effects of storage at Rankin Rapids on existing and potential power developments in New Brunswick have been evaluated in detail by the

Saint John River Board. The similar, although smaller, effects resulting from the construction of developments at Big Rapids and Lincoln School, have not been evaluated.

The effects of upstream storage on the power and energy generation at hydro-electric stations forming part of a utility system will vary with many factors among which are the following: - 15 -

(a) - The pattern of river flow.

(b) - The size, characteristics, and cost of other existing and potential generating facilities of the utility, particularly thermal generation.

(d) - The cost of the downstream hydro-electric stations.

(e) - Whether or not the upstream storage developments incorporate power stations subject to seduction in head with storage drawdown.

In the case of the Saint John River, the interaction of these factors is complex and the effects of upstream storage have been evaluated using a digital computer. However, an appreciation of the magnitude of these effects can be gained from Plate 2, which shows the modifying effects of Rankin Rapids storage and of the existing storages on typical natural flows (year 1933-34) at the Beechwood development. It was assumed that the Rankin Rapids development, when operated by itself or with the Passamaquoddy Tidal Power Project, will supply a load having the same characteristics as the present utility load in

Maine.

2. 3 - Potential Storages on Tributaries . of the Saint John River ~ ~~~

The potential storages on tributaries of the Saint john River, as

listed in Table 2, have live storage volumes totalling 2, 499, 500 acre-feet.

Individual storages vary in size from 30, 000 acre-feet at the Boundary Lake

site on the St. Francis River, to 535,000 acre-feet,at the Masardis site on - 16 -

the Aroostook River. The figures in Table 3 give some indication of the value of these storages and were used as a guide in the system studies described in subsequent sections of this report.

Capital costs of all of the developments, with the exception of

Ledges, were estimated on the basis of 1952 prices by the International Saint

John River Engineering Board. For purposes of the present study, they have been adjusted to take into account the rise in cost of labour and materials since that time, using an escalation factor. of 1. 23. No account was taken of flowage damages to lakeshore properties whith have been developed since 1952. The estimated capital cost of the Ledges storage development on the Tobique River, was obtained from The New Brunswick Electric Power Commission. All annual charges given in Table 3 were computed using an interest rate of 5.5 per cent and a depreciation charge of 0. 56 per cent on structures, no allowances being' made for taxes or water royalties.

Figures in the last column of Table 3 are a guide to the relative economy of the various potential storages as they represent the estimated costs of usable energy which may be obtained by storage control, assuming that the economic potential head of the Saint John River is developed. However, they do not represent the total value of the storages as additional benefits can be derived under some circumstances from an increase in the low flow dependability of downstream hydro-electric stations.

On the basis of January 1959, fuel costs, energy can be obtained

from the Lac Squatec storage at a cost which is less than the cost of incremental - 17 -

energy from modern thermal stations in New Brunswick, estimated to range from

3. 1 to 3.6 mills. The comparative economy of other storages was determined in

detail in the system studies.

It should be pointed out that all comparisons were made on the basis

of present day fuel costs and that if fuel costs increase, the value of minor

storages may also increase. TABLE 3

POTENTIAL STORAGES ON TRIBUTARIES OF THE SAINT JOHN RIVER - APPROXIMATE COSTS OF STORED ENERGY

Probable Maxiunum Approximate Estimated Approximate Net Head Energy Capital cost of Name Storage Below Equivalent of CQSt Annual Stored of Volume Storage Stored Water 1959 Charges Energy Development River Acre -Ft Ft Kwk $ $ Mills/Kwh

Storaees in Canada 6 D aaquam R ive r D aaquam 116, 000 333/2 35 x 10 7,760, 000 430, 000 12-3

Lac Squatec *: S quate c 133,500 333Q 40 x lo6 1, 969, 000 111, 000 2*8

Long Lake Cabano 34, 400 333Q 10 x 106 1, 095, 000 62, 000 6-2 .. Temiscouata Lake -Madawaska 429, 000 33311 120 x 106 15, 214, 000 841, 000 6:' 5 6 Jerry Lake Baker Brook 63,000 333 18 x 10 2,264,000 125, 000 6.9

Touladi Lake Touladi 1.00, 000 333L 30 x 106 4, 166, 000 233, 000 7.8

Ledges T ob ique 195, 000 223 39 x 106 7, 150,000 393, 000 10.1

International Storage s ~ ~

Glazier Lake St. Francis 333,000 333 100 x 106 10,391,000 595, 000 6.0

16 lo6 1, 7.34,ooo 95, 000 . Lac de L'Est Chimenticook 56, 600 33312 x 5.4. .. Boundary Lake St. Francis 30, 000 333 9 x 106 1,544,000 85,000 9.4 Table 3 - 2

Probable Maximum Approximate Estimated Approximate Net Head Energy Capital cost of Name Stor ag e Below Equivalent of cost Annual Stored of Volume Storage Stored Water 1959 Charges Energy Development River Acre- Ft Ft Kwh $ $ Mills /&h

Storages in the United States

Masardis Ar o o sto ok 535,000 310-13 150 x lo6 12, 070, 000 708, 000 4. 7

Eagle Lake Fish 65,000 333 20 x 106 1,700,000 93, 500 5.5

St. Froid Lake Fish 115, 000 333 35 x 106 3,866,000 225, 000 6. 4

Fish River Lake Fish ' 124,000 333 37 x 106 3, 149, 000 186, 000 5. 0

Twelve Mile Machias 170,000 310-13 48 x lo6 7, 624, 000 42, 000 8. 7

/1 The probable maximum net head of 333 feet downstream from Lac Squatec, Long Lake, Temiscouata Lake, and Touladi Lake, does not include the 20-foot head developed at the existing Edrnundston plant on the Madawaska River.

!? The probable maximum net head of 333 feet below Lac de L'Est and Daaquam River excludes any head which can be developed at Rankin Rapids.

-13 The probable maximum net head of 310 feet below the Masardis and Twelve Mile storage sites includes a total of 99 feet at existing Maine Public Service Company plants of Caribou and Tinker Falls and a potential head of 58 feet at the Castle Hill site in the State of Maine. - 20 -

3 - NEW BRUNSWICK ELECTRIC UTILITIES

The total nameplate rating of installed generating facilities in the

Province of New Brunswick in 1959 amounted to 375. 6 megawatts of which

100. 8 megawatts or 26.8 per cent is owned and operated by industries engaged primarily in the manufacture of pulp and paper. The remaining 274.8 megawatts is owned by electric utilities, the largest of which is The New Brunswick

Electric Power Commission. A summary of industrial and utility generation in the province is given in Table 4.

Out of a total of 186. 4 megawatts of installed hydro-electric capacity in the province, the developments on the Saint John River and its tributaries in New Brunswick account for 167. 7 megawatts. Of this amount, 155 megawatts is located in plants at Grand Falls, Tobique and Beechwood, and the remaining 12.7 megawatts is distributed among three small developments, all of which are located on tributaries. Salient features of these existing developments are described in Section A6 of the Appendix, and the installed capacities are listed in Table 5.

The three small plants on tributaries of the Saint John River will not be affected by upstream storage in any of the sequences of development which have been considered in this report. However, development of storage on the upper Saint John River and its tributaries will have significant effects on the output and operation of the Grand Falls, Beechwood and Tobique developments, all of which are owned and operated by The New Brunswick - 21 -

TABLE 4

INDUSTRIAL AND UTILITY GENERATION IN NEW BRUNSWICK 1959

Nameplate Rating - Mw Owner Location Hydro Thermal

Industrial

Atlantic Sugar Refineries Limited Saint J ohn 2.3 Bathurst Power and Paper Company Limited Nepisiguit River - B athur st 22. 1 Fraser Companies Limited E dmunds t on 19. 3 Fraser Gompanies Limited Atholville 11.0 Fraser Companies Limited New castle 4. 5 Irving Pulp and Paper Company Lancaster 12. 0 New Brunswick International Paper Company Dalhousie 19. 0 St. George Pulp and Paper Company Limited St. George -

Total Industrial Generation . , a . . . a 90. 2

Utility

The New Brunswick Electric Power Commission Various locztions 164.7 92.3 Maine and New Brunswick Electrical Power Company Aro o s took Limited River 10.0 1.0 City of Edmundston Green River 1.1 3.0 City of Campbellton Campbellton - 2;’7

Total Utility Generation . *. a. o. e m... . 175. 8 99. 0

Total Industrial Generation a. a . . . *. . . 10. 6 90.2

GRAND TOTAL. -. *. -.. -. Do 186.4 189.2 /- - 22 -

TABLE 5

EXISTING HYDRO- E LE CTRIC DEVELOPMENTS ON THE SAINT JOHN RIVER AND ITS TRIBUTARIES IN NEW BRUNSWICK

Name of Nameplat e Development Owner River Rating - Mw

Tinker Falls Maine andNew Brunswick Electrical Power Company Limited Ar o o s took 10. 0

Second Falls City of Edrnundston Green 1. 1

E dmund s t on Fr as er C ompanie s

' Limited Madawaska 1. 6

T obique N. BoE. P. C. T obique 20. 0

Beechwood N. B. E. P. C. Saint John 72. 0

Grand Falls N. B. E:P. C.-/1 Saint John 63. 0

Total ...... OO...... O...... 167. 7

On May 1, 1959, ownership of the Grand Falls plant was transferred to The New Brunswick Electric Power C omxni s sion. - 23 -

Electric Power Commission. A detailed study of The New Brunswick Electric

Power Commission system was therefore undertaken by the Board and the basic data used in this study are presented in the following sections.

3. 1 - Definitions

Before giving details of the system of The New Brunswick Electric

Power Commission, it will be of value to define a number of terms which will be used. Except where otherwise stated in this report, the capacity of any generating station is measured at the low-tension bus.

Firm Power and Energy - The major portion of the power and energy generated by any electric utility is supplied to customers on a continuing basis,

subject to interruption only as a result of very unusual or unforeseen circum-

stances or acts of God. Such power and energy is described as firm.

Secondary Power and Energy - All power and energy sold on an inter-

ruptable basis is described as secondary. The supply of secondary energy

may be interrupted for a variety of reasons, such as low river flow or the

outage of generating equipment. It may also be interrupted around the the

of daily firm peak demand.

Load Factor - Load factor is the ratio of average power to peak power

supplied to meet a load, or group of loads, during a stated period of time.

Rated Capacity- The rated capacity of a hydro-electric plact is defined

as the sum of the power outputs allowable from each unit in the plant when

operating singly at maximum head. Under this definition, rated capacity is - 24 -

a measure of the total amount of generating equipment installed. Rated capacity of a thermal plant is defined as the total capacity which can.be used to meet the load demand and station service requirements

Net Capability - The net capability of a hydro-electric development is the maximum power output with all units operating, and with no spillage at the development. The net capability of a thermal plant is defined as the rated capa-

city less station service requirements.

Flood Dependability - For the purposes of this report, the flood depend-

ability of a hydro-electric development is defined as the maximu power output

obtainable at the station during a fall flood having an estimated probability of

occurrence of 5 per cent. Although spring floods of the Saint JohnRiver are usually of greater magr&ude, fall floods have been known to occur as late as

December when power demand on the system of The New Brunswick Electric

Power Commission.is at, or n.ear, the maximum. For this reason, reduc-

tion in capacity during a fall flood can be more critical than during a spring

flood.

Low Flow Dependability- The low flow dependability of the system of

The New Brunswick Electric Power Commission with any given set of plant

installations, is defined as the firm power demand which those installations

can meet with river flows as low as have been experienced during the period

of river flow recordp which is 42 years in length. A similar definition applies

when the system of The New Brunswick Electric Power Commission is operated

integrally with adjacent utility systems. .. .

- 25 .-

Spinning Reserve - During normal operation of a utility system, a limited

amount or" capacity over and above that required to meet the load demand is

maintained on operating units. Such capacity is called spinning reserve.

Capacity Factor - The capacity factor of a generating station has been

taken as the ratio of average power output to net capability, for any stated

period of time.

3.2 - Load Growth

In 1959 the gross peak demand on the system of The New Brunswick

Electric Power Commission was 220.2 megawatts or approximately 65 per cent

of the estimated total industrial and utility peak demand of the province. The

gross energy demand in 1959 was approximately 1, 066 million kilowatthours,

giving a load factor of 55.3 per cent. The distribution of gross energy demand

in 1959 is given in Table 6. The firm peak demand on the system in 1959 was

151 megawatts at a load factor of 51 9 per cent.

The major portion of secondary energy generation in 1959 was

supplied to the New Brunswick International Paper Company and Fraser

Companies Limited under contracts which were taken over by The New Brunswick

Electric Power Commission when ownership of the Grand Falls plant was trans-

ferred from the Gatineau Power Company on May 1, 1959, The amounts of

power and energy supplied under these contracts are related to river flow

at the Grand Falls plant, and circumstances can therefore arise in which the

full output of the plant, namely 60 megawatts, may have to be supplied co-

incidentally with anncal peak demand on the Commission's system. For the - 26 -

TABLE 6

DISTRIBUTION OF ENERGY DEMAND BY CLASS OF SERVICE - 1959 - NoBo E. P. C. SYSTEM

Annual Energy Class of Service Demand - Kwh

Firm Energy

Wholesale ...... ~~~~*~~~~~~~ 273,522, 985 Industrial at transmission voltage. -. e e 57,265, 600 Domestic, commercial and industrial at

distribution voltage e a *. a a ., a 268,122, 620 Station service...... ,...,...... ,.~~~~~~ 25,868, 790 Transmission and transformation loss -. e -.a e ,, 62, 138, 425

Total Firm Energy. e eo eo Do e 686,918, 420

Secondary Energy

New Brunswick International Paper Company and Fraser Companies Limited under contracts taken over from

Gatineau Power Company e v. e e 265,996,800

Other pulp and paper companies e e a ,, e 74,144,500

Connectedutilities ., a e a e en ., e ,, ., 38,992,400

Total Secondary En.ergy, . e e 379,133,700

Total Firm Energy. ., e eo. e a I) ., a a 686,918,420 - 27 -

purpose of this study, the loads of the New Brunswick International Paper

Company and Fraser Companies Limited have been assumed by the Saint John

River Board to be firm, with a peak of 60 megawatts.

Although the magnitude of benefits from upstream storage on the

Saint John River is related primarily to the installed capacity downstream, the growth of firm power and energy demand on The New Brunswick Electric

Power Commission system was of importance in the studies in that variation in future growth could cause changes in the economic sequence of development.

A graph showing the growth of firm power and energy demand on the system of The New Brunswick Electric Power Commission is given on Plate 3.

Growth has been at a fairly uniform high rate since 1924, there being a slight increase in the rate of growth after the Second World War. From 1945 to

1959, the increase in firm annual power demand has been at the rate of 11.5 per cent, excluding the unusual growth in the year 1948 which resulted from acquisition by the Power Commission of the New Brunswick Power Company.

As power and energy supplied from the Grand Falls plant to the

New Brunswick International Paper Company and Fraser Companies Limited have been assumed as firm load by the Saint John River Board, the gross firm peak load in 1959 would have been 211 megzwatts. I-Iowever, the rate of growth of loads of this type has been comparatively low in the past, and it is estimated that the inclusion of these loads as firm demand will effectively reduce the overall rate of system load grown in the innmediate future to approximately

9.4 per cent. - 28 -

In estimating the probable future rate of load growth, it is useful to divide firm load demand' into two por.tions, namely, domestic and commercial, and firm industrial. The New Brunswick Electric Power Commission serves domestic andcommercial consumers bothdirectlyandthrough several distribution utilities. Unfortunately, figures of past growth of the domestic and commercial load of the minor utilities are rrot available. However, a reasonable picture ofthe pattern of past growth canbe obtained by considering the history of direct sales by the Commissionto domestic and commercial consumers, as given in Table 7.

,TABLE 7

AVERAGE ANNUAL AMOUNT OF ENERGY SOLD DIRECTLY TO DQMESTIC AND COMMERCIAL CONSUMERS - N. B. E. P. C. SYSTEM .

Average Use Average Use Per Customer Number of Total Consumption Per Customer in Canada,/1 Year Customers Million Kwh Kwh Kwh 1940 17, 400 6 329 - 1945 23,900 8 345 2,191

1950 51,700 37 711 22 997 1955 69,500 72 1, 033 4, 231 1957 78,100 103 1, 316 4,864 1959 84, 000 134 1, 600 -

!1 Obtained from data published by the Dominion Bureau of Statistics.

From 1940 to 1950, the average use per customer increased at the rate of 8 per cent per year and the number of customers increased at the rate - 29 -

of 11.5 per cent. From 1950 to the present time, growth in annual consumption per customer has been at the rate of 9.4 per cent, and the number of customers has increased at the rate of 5. 5 per cent per year. However, in spite of the very substantial past growth, the figure of 1, 600 kilowatthours consumption per customer in 1959 is less than half that of the national average which is in excess of 4, 500 kilowatthours. There would appear to be little doubt that the present rapid rate of growth in domestic and commercial load will be maintained for many years to come.

Sales of firm power to industry, while following an upward trend, have nevertheless shown considerable fluctuation in the past, reflecting to a far greater extent than domestic sales, the fluctuations in the level of economic activity in the province. During the war years, industrial sales increased from

12. 5 million to 27 million kilowatthours, whereas immediately following the war there was a decline, and sales did not again reach the 1945 peak until three years later. After 1948, the rate of growth again increased and was rnaintained at a fairly steady rate.

Based on past experience, it can be said that sales of firm power to industry, while showing an upward trend, can be expected to fluctuate considerably in the future, and there will be a substantial growth in sales to domestic and commercial consumers. Therefore, it is assumed that growth for total firm load will continue for some time at the rate predicted for the immediate future, namely, 9.4 per cent per annum. It is also assumed that the annual load factor and load characteristics will remain constant. However, - 30 -

development of the mineral potential in the province could have a major effect on these estimates.

From an analysis of the characteristics of firm load demand in recent years, and after making suitable adjustments for the load of the New

Brunswick International Paper Company and Fraser Companie s Limited, included by the Board as firm demand, it was found that the monthly load duration curve when expressed as a percentage of the monthly peak demand, remains sensibly constant for all months of a year, the monthly load factor being

67. 6 per cent. The monthly load duration curve used in the studies is plotted on Plate 4, and the shape of this curve was of importance in the studies in that the dependable capacity of hydro-electric developments on the system is directly related to the amount of energy required in meeting a load of a given amount at the top of this curve.

The monthly variations in peak demand and energy demand are also important characteristics of a utility load, which must be taken into account in determining the economy of new sources of power. The effect of load growth is, of course, superimposed upon the seasonal variation in energy and peak power demandg and in the system studies it was necessary to separate these two effects. The monthly demand factors =sed in the study were obtained by removing the effect of load growth from past records and are given in Table

8. As the monthly load factor remains sensibly constant, the factors given in

Table 8 are applicable equally to energy and peak power demand. - 31 -

TABLE 8

MONTHLY FIRM POWER AND ENERGY DEMAND FACTORS (EFFECT OF LOAD GROWTH REMOVED) - NoBo E. P. C. SYSTEM

Month Factor

January ...... 0 963 February ...... 888

March ...... D 862 April ...... 842

May. eo a O.D 845

June e a a e O.D Do 847

July ...... a 845 August ...... 846

September ~..O~~D~~~O~O.~~ODOO~~~~~879

October. e a D. a 896

November Do~DoDD~oooo~oDooooo~~~~~a 965

December oo e e a 1.000

At the present time, secondary energy, primarily from thermal stations, is sold by The New Brunswick Electric Power Commission to pulp and paper mills in the province, and on an interchange basis to the Maine

Public Service Company. Since 1940 these sales, although varying widely, have been substantial and have become a significant source of revenue. However, it is expected that secondary loads will become a decreasing percentage of the total load in the future, and that sales of surplus hydro energy will be insig- nificant in the long term. All economic calculations were therefore based upon the sale of firm power and energy only.

The distribution of firm load demand throughout the province and possible future trends in this distribution, were of importance in estimating - .32 .-

the manner in which the transmission network of The New Brunswick Electric

Power Commission will be expanded. . Estimates of future load distribution, supplied by The New Brunswick Electric Power Commission, are given in

Table 9.

TABLE 9

ESTIMATED FUTURE DISTRIBUTION OF FIRM LOAD DEMAND IN MEGAWATTS - N. B. E. P, C. SYSTEM

Load Area 1960 1965 1970 1975 1980

Bathurst a e *. . . 12,8 25.0 45.9 83. 2 144.0

Chatham e.OOOO.ODD.D.DO 15.9 24.9 38.5- 58.0 85. 0

Moncton D.. . e e.. a e 45.0 71.8 110.0 167-1 250.0

Saint John e *.. . . 45.6 71. 2 107.5 157.6 229.0

Grand Lake. a D. a 7.3 11.4 16. 6 23.5 33.1

Fredericton .o.. e m. 27.6 49.0 86. 2 150. 0 252.0

Upper Valley ; 7. 6 14. 1 25.7 44.7 74.9

Dalhousie . . e e 46.6 53.8 61. 3 68.9 77. 8

Edmundston o.. 18. 6 22.8 28. 3 35.0 44.2

Total Do 227.0 344.0 520.0 788. 0 1, 190. 0 - 33. -

3. 3 - Hvdro-Electric Generation

Excluding the two small diesel plants on Campobello and

Grand Manan Islands, the generating facilities of The New Brunswick

Electric Power Commission, in December 1959, had a nameplate rating of 257 megawatts, of which 164.7 megawatts was in hydro-electric

stations. The Musquash development near Saint John, with a net capability of 7 megawatts, was commissioned in 1922 and was used to supply the initial load demand on the system. Thereafter, the load was met by a number of thermal stations, until the Tobique development was commissioned in 1953. As the load continued to increase, it became apparent that output from a major hydro-electric development on the Saint John River could be absorbed economically by the system, and in 1957 the Beechwood development came into

service. The Milltown development on the St. Croix River, with a net capability of 1.7 megawatts, was purchased by the Commission in 1958, and on May 1, 1959, ownership of the Grand Falls development was transferred from the Gatineau Power Company to the Corn- mission. The nameplate rating s , net capabilities, and flood capabilities of hydro-electric developments of The New Brunswick Electric

Power Commission's system are given in Table 10, and salient features of the Tobique, Beechwood and Grand Falls developments are described in Section A6 of the Appendix. TABLE 10

CAPACITY OF EXISTING HYDRO-ELECTRIC PLANTS IN DECEMBER 1959 - N. B. E. P. C, SYSTEM

Total Net Head Plant Nameplate Plant Net at Full Flood Name of bTumb e r Rating Capability output Capability Development River of Units Mw Mw Ft Mw

Musquash Mu. s qua sh 3 7.0 7.0 s 7.0-11

T obique T obique 2 20.0 19.0 70. 0 15.. 2 I Beechwood Saint John 2 72. 0 69.5 59.1 51. 8 w I+ I Milltown St. Croix 4 2.7 1.7-12 - 1.7-11

Grand Falls Saint John 4 63.0 60.0 . 123.8 51. 3

Total e *. *. e - - -164.7 -157..2 -.11 Assuxned.

/2 The net capability has been arbitrarily reduced due to lack of forebay capacity. - 35 -

The Musquash and Milltown developments, with a total net capability of 8.7 megawatts, represent a .very small proportion of the system, and. changes in net capability due to rise in tailwater level during floods were neglected. The total energy output from these developments is also small and it was considered sufficiently accurate to use long term average energy outputs as given in Tables 11 and 12.

TABLE 11

MUSQUASH DEVELOPMENT

Mean Monthlv Enerpv Outtmts

~~ ~~~ Output in Million Month Kilowatthour s January ...... 2.4 February ...... 2.2

March DOOD~OOODOOD~DO..~~O~~~~~~..2. 6 April ...... 2.7

May ..D.~.OO.D.OO~OOOOOO~~~~~~~~~2.1 June...... 1.2

July ~DoDoooDDD~DoDoDDDDo~~~~~~~~~0.9 August ...... 0.8 September De om a -. 0.7

October O.DD~DDOOOODDOOOODOO~~~~~~1. 1 November...... 1. 6

December OO.O~ODOODDO~~~~DOD~~~~~2-2

Mean Annual Energy Output. 20. 5

The outputs shown above were obtaijned by averaging - the monthly outputs obtained during the period from . 1937 to 1958. - 36 -

TABLE 12

MILLTOWN DEVELOPMENT

Mean Monthly Energy Outputs

Output in Million Month Kilowatthour s

1.72 1.52 1. 60 1.20 1. 38 1.56 1. 70 1. 64 1.55 1. 72 1. 61 1, 69

Mean Annual Energy Output e a. 18.89

As generation records were not available, the outputs shown above are based on the long term average monthly flo-ws of the St. Croix River.

Energy outputs from the major hydro-electric developments on the Saint John and Tobique Rivers vary with river flow and with the amount of upstream

storage available, as described in subsequent sections of this report.

The greater portion of the hydro- electric potential of the

Province of New Brunswick is located on the Saint John River ,and its tributaries. With the possible exception of the Castle Hill site OE the Aroostook

River with a potential capacity of 18 megawatts, all power sites on tributaries - 37 -

of the Saint JohnRiver were shown to be uneconomic in 1953 bythe International

Saint John River Engineering Board. Undeveloped reaches of the main stem of the Saint John River in New Brunswick are:

(a)- The reach between Rankin Rapids and Grand Falls headpond in which the river drops approximately 123 feet.

(b) - The rea.ch between Grand Falls and the Beechwood headpond in which the river drops approximately 58 feet.

(d) - The reach from Woodstock to tidehead near Fredericton in which the river drops approximately. 110 feet.

(e)- The reach below tidehead.

A number of possible power sites in these reaches ofthe riverwere studied in apreliminary manner between 1951 znd 1953 by the International

Saint John River Engineering Board, the estimates of capital cost which were prepared at that time being based upon preliminary field investigation. On the basis of this previous work, it was considered unnecessary to give further attention to the reach of the river between Rankin Rapids and the Grand Falls headpond. The power potential of the river below tidehead was not studied as it would probably have to be developed in conjunction with Saint John harbour improvements These improvements are under study by the Department of Public Works, and details of its proposals are not yet available.

The selection of power sites in the remaining three reaches, and the revised layouts and estimates of capital cost prepared by the Saint John

River Board, have been based upon more extensive topographical and - 37 -

of the Saint JohnRiver were shown to be uneconomic in 1953 bythe International

Saint John River Engineering Board. Undeveloped reaches of the main stem of the Saint John River in New Brunswick are:

(a) - The reach between Rankin Rapids and Grand Falls headpond in which the river drops approximately 123 feet.

(b) - The reach between Grand Falls and the Beechwood headpond in which the river drops approximately 58 feet.

(a) - The reach from Woodstock to tidehead near Fredericton in which the river drops approximately 110 feet.

(e) - The reach below tidehead.

A number of possible power sites in these reaches of the river were studied in apreliminary manner between 1951 and 1953 by the International

Saint John River Engineering Board, the estimates of capital cost which were prepared at that time being based upon preliminary field investigation. On the basis of this previous work, it was considered unnecessary to give further attention to the reach of the river between Rankin Rapids and the Grand Falls headpond. The power potential of the river below tidehead was not studied as it would probably have to be developed in conjunction with Saint John harbour improvements. These improvements are under study by the Department of Public Works, and details of its proposals are not yet available.

The selection of power sites in the remaining three reaches, and the revised layouts and estimates of capital cost prepared by the Saint John

River Board, have been based upon more extensive topographical and TABLE 13

POTENTIAL CAPACITY A.T UNDEVELOPED HYDRO- ELECTRIC SITES ON THE SAINT JOHN RIVER IN NEW BRUNSWICK ABOVE TIDEHEAD

Rated Capacity of Plant Rated Rated Plant Net Net Head at Plant Flood Name of Nmber One Unit Capacity Head Capability Full Output Capability B evelomnent of Units MW Mw Ft Mw Ft Mw

Mactaquac 2 121.0 115.0 98.9 92.7 3 181.5 170. 0 97.6 139.1 4 242.0 223.6 96.4 185.5 5 60.5 302.5 100 273.0 95.3 229.2 6 363.0 320.0 94.4 274.4 I 7 423.5 367.0 93. 6 321.5 w 9 8 484.0 414. 0 92.8 367.0 I

Morrill 2 5tj00 52.4 57.0 41.7 3 27.5 82. 5 57 75.7 55.4 62. 6 4 110.0 98. 0 54.2 83. 5

~~~~ ~~ ~ Hawkshaw-I1 2 77. 6 72.7 63.4 46. 6 3 38.8 114.4 65.3 105.7 61.5 69.9 4 155.2 136.7 59.6 93.2

!! The Hawkshaw site will be flooded if the Mactaquac 'site is developed. The two developments are therefore alternatives. TABLE 14

POTENTLAL CAPACITY AT DEVELOPED HYDRO-.ELECTRIC SITEiS ON THE SAINT JOHN RIVER

Rated Total Rated Total Net Total Flood Number Capacity of Capacity of Rated Capability of Net Head at Capability of Name of of Units in One Unit Extension Head Extension Full Output Ext en s ion

Beechwood 1 36. 2 36. 2 61.4 31. 5 57.8 25. 9 2 72.4 62.4 56. 3 51. 8 I

Grand Falls 2 94.4 82. 6 125.0 74.9 3 141.6 121.5 123.8 112.3 I 4 47.2 188.8 132.0 159.2 122.8 149.8 5 236.0 195.0 122.0 181.. 7 6 283.2 229.0 121.4 218. 2 - 41 -

progressively, as can be seen by comparing figures of rated capacity and net capability in Tables 13 and 14. For exaxnple, the first two units of the proposed Mactaquac development have a total net capability of 115 megawatts, whereas the seventh and eighth units, although of the same physical size, have a total net capability of only 94 megawatts.

During flood, the reduction in head, and hence loss of capacity, is greater due to the rise in tailwater levels. For example, the net capability of existing and potential generation of the Tobique and Saint John Rivers in

New Brunswick, amounting to 951.9 megawatts, would be reduced to 838.8 megawatts during a flood having a probability of occurrence of 5 per cent.

This represents a capacity loss of almost 12 per cent, a figure which is comparable to the reserve capacity normally required on systems of the size of

The New Brunswick Electric Power Commission.

Capacity losses of this magnitude can have a significant effect on

system reliability. No complete reliability studies have been carried out as part of the present work. Howeverp as major fall floods have occurred as late as December of any year when the system load demand is at, or near, the peak, sufficient reserve capacity was maintained in all sequences of development to replace capacity which would be lost during fall floods having a. probability of occurrence of 5 per cent, Table 15 gives the estimated peak flows during such floods at the various power sites which were considered.

The derivation of these flows is explained in Section A4 of the Appendix., - 42 -

.TABLE 15

5 PER CENT PROBABILITY FALL FLOODS AT EXISTING MDPOTENTIAL POWER DEVELOPMENTS ON THE SAINT JOHN AND TOBIQUE RIVERS

Name of Estimated Flow Development Cfs

Grand Falls a me ., Do 70,000 Morrill...... 73,000 Tobique ...... 35,000

Beechwood D~ODOOO.OO~OO~DIDO~ODDOO 122,000 Hawkshaw...... 172,000

Mactaquac OODOOD~OOOO~dDID~ODD~~~~190,000

Power developments on the Saint John River will be of value in the future as peaking stations during times of low river flow, and forebay drawdown will be a factor to be considered, as is demonstrated by the figures in

Table 16. The last column of this table gives the number of hours for which the various plants can be run at maximum capacity under typical February flow conditions, and with a maximum forebay drawdown of 5 feet.

The proposed Mactaquac development is an alternative to the

Hawkshaw development and is much superior as a peaking plant, in that it could operate at maximum capacity for almost 18 hours with a drawdown of only 5 feet, whereas the Hawkshaw development could operate under similar conditions for less than 10 hours. The existing Tobique plant also has ample pondage for peak load operation, The forebay capacities at Beechwood and

Grand Falls and at the potential development at Morrill, although sufficient TABLE 16

PONDAGE AT EXISTING AND POTENTIAL POWER DEVELOPMENTS ON THE SAINT JOHN AND TOBIQUE RIVERS

Forebay Typical Hours of Peaking Net Surface Pondage for February at Net Plant Capa- Name of Capability Area 5-FOOt Drawdown Flow bility with 5-Foot Development in Mw Acres Acre-Feet Cfs Drawdown

Grand Falls 289.0 3, 460 14,900 3,200 5.69

Morrill 98, 0 2,006 9,600 3,400 5-38

Tobique 19. 0 1,000 4,850 5 65 18.60

Beechwood 101.0 2,700 12,500 7,110 8.95

Hawkshaw -/1 136.7 4,200 18,400 8,100 '9.75

Mactaquac .414.0 15,800 76,000 8,400 17.70

-/1 The Hawkshaw site will be flooded if the Mactaquac site is developed. - 44 '-

for peak load operation are? nevertheless, limited and, in the case of Grand

Falls, a detailed study of forebay drawdown will be required if a storage and power development .is constructed at Rankin Rapids and operated to firm up the daily fluctuations in power output from the Passamaquoddy Tidal Power

Project.

The actual forebay drawdown which will be experienced in the futur.e

at power developments on the Saint John River will vary with plant installation and with river flow. In the system studies which will be subsequently described

in detail, it .was assumed that the average head and thus the energy output at

.the various power developments would be reduced by the percentages given

in Table 17, due to forebay' drawdown under average conditions of base load and peak load operation,

TABLE 17

ASSUMED PERCENTAGE REDUCTIONS IN HEAD DUE TO FOREBAY DRAWDOWN

Percentage Reductions in Head Name of Base Load Peak Load Development Operation Ope ration

Grand Falls 1

MorrilL e e e 1 Tobique ., 0 Beechwood ., 1 Hawkshaw. 1 Mactaquac 1 - 45 -

The net head at the Grand Falls development is more than twice the net heads at Morrill, Beechwood, or Hawkshaw, and a lower percentage reduction inheadwill consequently be experienced during peak load operation.

On the other hand, the Mactaquac development, which also has a head substantially greater than at Morrill, Beechwood, or Hawkshaw, would normally be operatedatalow load factor under conditions of low river flow. The percentage reductioninheadwas therefore assurnedto be the same as at Beechwood.

3.4 - Thermal-Electric Generation

In 1959 the nameplate rating of thermal-electric generating facilities of The New Brunswick Electric Power Cornmission amounted to 92.3 megawatts or 36 per cent of the total generation owned by the Commission.

The first two thermal-electric units installedby The New Brunswick

Electricpower Commissionin 1931 are atGrandLakeNo. 1 plantandhavename- plate ratings of 2.5 megawatts each. Starting in 1936, other thermal-electric units were installed or purchased, the largest and most recent being the 20- megawatt unit at the Chatham plant installed in 1956. The nameplate rating and net capability of all thermal-electric stations of the system are given in

Table 18.

The majority of existing units are of small capacity and the cost of energy generated by these units is high in comparisonwithmodernunits of a size which couldnow be utilized on the system of The New BrunswickElectric

Power Commission. A 50-megawattunit is being installed in a new station under construction at East Saint John and is scheduled for commissioning in - 46 -

TABLE 18

NAMEPLATE RATING AND NET CAPABZLIT'Y OF EXISTING THERMAL-ELECTRIC PLANTS - 1959 N. B. E, P. C. SYSTEM

Nameplate Net Rating Capability Plant Name Mw Mw

Saint John. *. - 16. 0 16.0 Grand Lake No. 1. e e a 18.8 18.0

Grand Lake No. 2 e.. *. 25.0 29.0

Chatham *. . e e De D. e 32.5 36.0

Total. *. *. D.. . D. 92.3 99.0

Note: The diesel plants on Campobello and Grand Manan Islands .having an aggregate rated capacity of one megawatt are not included in the tabulation.

mid- 1961. Energy produced at this station will be at costs substantially less than for existing units on the system, and provision is being made to burn either coal or oil. Cooling water capacity is being provided for a total installation of at least 250 megawatts.

As the system load increases, the size of any thermal units which may be required to firm up hydro-electric generation on the Saint John River will also increase. The net capabilities of thermal-electric units considered in the Sequences of development are given in Table 19.

Important considerations in locating thermal-electric plants are the availability of adequate supplies of condensing water, the cost of fuel at - 47 -

TABLE 19

NAMEPLATE RATING AND NET GENERATING CAPABILITY OF TYPICAL MODERN THERMAL-ELECTRIC UNITS

Nameplate Net Generating R at ing Capability .Mw MW

50 48. 2 75 72. 5 100 96. 3 150 143.4

site, and proximity to load centres. Many of the load centres in New Brunswick are on the coast where ample supplies of condensing water are available and where fuel can be delivered at attractive rates. Similar conditions also apply in the Grand Lake area.

In the various sequences of development which have been studied, additional thermal generation, when economic, has been provided at Saint

John, Bathurst, and Grand Lake. In all cases, it has been assuzmed that the plants will utilize the cheapest available fuel.

3.5 - Generation Costs

Capital Costs - The topographical and geological information available and the methods applied in preparing layouts and estimates of capital cost lor potential hydro-electric developments on the Saint John River in New

Brunswick, ar.e described in detail in Section A7 of the Appendix. Sufficient - 48 -

exploratory work was carried out by The New Brunswick Electric Power

Commission to enable the Board to appraise foundation conditions in the

power reaches and at the sites of potential developments.

The study of foundation conditions was carried to the point at

which it was certain that design and construction would not entail either the

. solution of unusual technical problems or the application of construction

methods for which there is no precedent. In all cases, sufficient spillway

capacity was provided in the layouts to pass the estimated maximum possible

flood.

To arrive at reliable cost estimates, attention was given to the

basic dimensions of the structures, their relation to each other, and to all

other factors which can have a major ,influence on the overall cost of the de-

velopments. However, detailed design studies of structures were not made.

Allowances wer.e made in the estimates of capital cost to cover the construc-

tion of fish-passing facilities, the choice and design of which will require

considerable study in the future.

Unit and lurnp surn pr.ices included in the estimates of capital

cost were based upon January 1959 costs of labour and materials and upon

recent quotations by equipment manufacturers. In all cases, it was assumed

that work would be constructed under unit price contracts. The estimates

ar.e complete in all respects and include the cost of direct it.ems, construc-

tion services, design, field supervision, and inspect.ion, interest during con-

struction, and a 10 per cent allowance for contingencies. Flowage costs - 49 -

were based on field surveys by The New Brunswick Electric Power Commission and include the cost of land acquisition, purchase of buildings, and highway and railway relocation. Estimated capital costs for alternative installations at each of the potential hydro-electric developments are given in Tables 20 and 21.

TABLE 20

ESTIMATED CAPITAL COSTS FOR POTENTIAL HYDRO-ELECTRIC DEVELOPMENTS ON THE SAINT JOHN RIVER

Net Estimated Name of Number Capability Capital Cost Development of Units Mw Dollars

Mactaquac. 4 223. 6 94,592, 000 5 273. 0 101,676, 000 6 320.0 109,078, ooo 7 367. 0 116,162, 000 8 414. 0 123,564, 000

Mor r ill 2 52, 4 31 , 465, 000 3 75.7 35,401, 000 4 98. 0 40, 394, 000

Hawkshaw-/1 2 72. 7 45, 177, 000 3 105.7 49,796, 000 4 136.7 55, 082, 000

-/1 The Hawkshaw site will be flooded if the Mactaquac site is developed. - 50 -

TABLE 21

ESTIMATED CAPITAL COSTS OF EXTENSIONS AT DEVELOPED HYDRO-ELECTRIC SITES ON THE SAINT JOHN RIVER

Existing Net Estimated Name of or Number Capability Capit a1 Development Future of Units Mw Cost

B eechwood Existing 2 69.5 - Future 1 101.0 $ 3, 040, 000 Future . 2 131.9 11,423, 000 Grand Falls Existing 4 60.0 - Future 2 142.6 18,374,000 Future 3 181.5 25,579,000 Future 4 219.2 35,685,000 Future 5 255.0 42,890, 000 Future 6 289.0 49,793,000

The estimated capital costs for new thermal-electric units in New

Brunswick, of the various sizes considered in the studies, are given in Table 22.

In all cases, it has been assumed that there willbe two units in each station.

TABLE 22

ESTIMATED CAPITAL COSTS OF TYPICAL MODERN THERMAL-ELECTRIC UNITS IN NEW BRUNSWICK

~~ Nameplate Estimated Rating Number of Units Capital Cost Mw Per Station Dollars /Kw

50 2 162 75 2 154 100 2 148 150 2 142 .. - 51 -

The average number of hours per year during which these units

will be operated will vary, depending upon the system load factor, the sequence

of development and the amount of hydro- electric generation installed in the

future. Estimated capital costs given in Table 22 have been based upon average

operation of 4,500 hours per year over the service life of the unito

As cooling water capacity for a total installation of at least 250

megawatts is being provided with the first unit at the East Saint John Thermal

plant, the capital cost of incremental capacity at this plant will be low. Based

on January 1959 prices, the incremental capital cost is estimated to be $126.00

per kilowatt

Annual Charges - Annual charges for a hydro-electric station represent

the total araual cost of capacity and energy generated at the station and alloca-

tion of these annual charges between capacity and’energy can only be arbitrary.

However , with thermal-electric stations, allocation of annual charges in this

manner is feasible.

The methods used in computing annual charges for new generating

facilities in New Brunswick for economic studies are described in the fo1l.owing

paragraphs and are based upon the experience and consistent practice of The

New Brunswick Electric Power Commission. These methods follow closely

those employed by the United States Federal Power Commission in similar

studies

Interest Charges - As the initial capital investment required in con-

structing a hydro-electric development is generally greater than for a - 52 -

thermal-electric, station of equivalent size, the interest rate paid on bonds is of major importance in studies of comparative economy. The approximate yield to maturity for provincial bonds issued by New Brunswick during the last 12 years for the construction of power system facilities has varied from a minimum of approximately 3.5 per cent in 1948 to a maximum of 5.5 per cent in 1960. Although interest rates may continue at a fairly high level for several years, the long term future interest rate is unknown,, In the system studies, an interest rate of 5.5 per cent has been employed.

Depreciation - Depreciation on generating facilities is a function of the expected life of these facilities and sinking fund interest rates. In accordance with the current practice of The New Brunswick Electric Power Commission in economic studies, the useful life of hydro-electric and thermal-electric stations has been assumed to be 50 and 35 years, respectively. A sinking fund interest rate one per cent less than the interest rate for new capital has been used.

Interim Replacement - As some elements and items of equipment in generating stations have a useful life less than the figures given above, provision has to be made for their replacement, Annual charges for hydro- electric and thermal-electric generating stations therefore include 0. 2 per cent and 0. 35 per cent, respectively, of the original capital investment to take care of such interim replacements.

Insurance - The annual cost of insuring all generating facilities was taken as 0. 1 per cent of the original capital cost. - 53 -

Taxes - The New Brunswick Electric Power Commission is a publicly owned utility and does not pay taxes.

Operation and Maintenance - The costs of operating and maintaining hydro-electric developments vary with the size of the station but do not vary appreciably with plant output. They include wages for operation and maintenance personnel and the cost of miscellaneous supplies. The figures used in computing annual charges for potential developments and for the extension of existing developments on the Saint John River in New Brunswick, are given in Tables 23 and 24.

TABLE 23

ESTIMATED OPERATION AND MAINTENANCE CHARGES FOR POTENTIAL HYDRO-ELECTRIC DEVELOPMENTS ON THE SAINT JOHN RIVER

Operation and Plant Net Maintenance Name of Number Capability Charges D evelopment of Units Mw Dollars / Y r

Mact aquac 4 223.6 365,400 5 273-0 450,700 6 320.0 526,400 7 367.0 601, 400 8 414.0 667, 900

Mor r ill 2 52.4 118, 300 3 75.7 150, 200 4 98. 0 180,400

Hawkshaw -/1 2 72.7 144,300 3 105.7 188, 600 4 136.7 240,600 -/1 The Hawkshaw site will be flooded if the Mactaquac site is developed. - 54 -

TABLE 24

ESTIMATED OPERATION AND MAINTENANCE CHARGES FOR EXTENSION TO EXISTING HYDRO- ELECTRIC DEVELOPMENTS ON THE SAINT JOHN RIVER

Operation and Maintenance Existing Plant Net Charges of Name of or Number Capability Extension, D evelopm ent Future of Units MW Dollars /.Y r

Bee chw ood Existing 2 69.5 - -/1 Future 1 101.0 96,500 Future 2 131.9 140, 600 Grand Falls Exi sting 4 60. 0 - -/1 Future 2 142.6 162,800 Future 3 181.5 219,500 Future 4 219.2 288,900 Futur e . 5 255.0 357,000 Future 6 289.0 424,800

!! Included in the lump sulll in subsection "Summary of Annual Charges".

The operation and maintenance costs for thermal-electric stations

are divided into fixed and variable components, depending on plant location,

labour and material costs, type of fuel, plant age and plant capacity factor.

Taking into account these variables as they apply to new thermal-

electric plants in New Brunswick, the fixed components of operation and maintenance costs have been estimated for unit sizes varying from 50 to 150 megawatts and are given in the second column of Table 25. The fixed component

of operation and maintenance costs for additional units installed in the East

Saint John Thermal plant, is estimated to be $0.56 per kilowatt per year. - 55 -

TABLE 25

OPERATION AND MAINTENANCE CHARGES FOR TYPICAL MODERN THERMAL-ELECTRIC GENERATING STATIONS IN NEW BRUNSWICK

Fixed Operation Variable Operation and Maintenance and Maintenance Unit Siz e Charges Charges Mw Dollar s 1Kw Mills /Kwh

50 2.20 0. 25 75 1. 76 0. 24 100 1. 38 0. 23 150 . 0. 84 0.22

The variable component of operation and maintenance charges for modern thermal-electric generating stations in New Brunswick has been computed assuming a useful life of 35 years and an average operating time of

4,500 hours per year. These figures are presented in the last column of

Table 25. The variable component of operation and maintenance charges for additional units at the East Saint John plant is estimated to be 0.25 mills per kilowatthour

Administration and General Expenses - A portion of such costs as the

salaries and expenses of Cornmission officers and employees, office supplies,

legal expenses, and welfare and pension funds, are chargeable against the

annual cost of generation. Based.upon the experience of The New Brunswick

Electric Power Commission, the proportions have been established as 35 per

cent of the total operation and maintenance charges for hydro-electric, - 56 -

development6 and 20 per cent of the fixed operation and maintenance costs

for thermal developments.

Interest on Reserve Fuel Supply - Fuel reserves are normally maintained at thermal- electric stations to ensure continuous operation during periods whensupply may be disrupted. FOPthe purpose of the present study

it was assumed that sufficient fuel would-be held inreserve to maintain plant

output for a period of 40 days.

Fixed Fuel -Costs - Significant amounts of fuel are consumed when a

thermal-electric plant is kept in operation at no load. In the present studies,

it was assumed that the fixed fuel component will represent 10 per cent of the total fuel consumed at new stations. Fixed fuel costs for new thermal-

electric units in New Brunswick ranging in size from 50 to 150 megawatts, have been calculated, assuming an average annual operation of 4,500 hours per year, and are given in the second colurnn of Table 26.

TABLE 26

FUEL COSTS FOR TYPICAL MODERN THERMAL-ELECTRIC STATIONS IN NEW BRUNSWICK

Fixed Fuel Incremental Cost-D ollar s Fuel Costs Unit Size Per Kilowatt Mills Per Mw Per Year Kilow atth our 50 1.66 3. 32 75 1.52 3. 04 100 1.49 2.98 150 1.44 2. 8'8

Note: These figures are based on a fuel cost at the burners of 35 cents per million Btu. - 57 -

Incremental Fuel Costs - Incremental fuel costs are a direct function of

energy produced and the figures given in the last column of Table 26 were based upoln use of the cheapest fuel delivered to the New Brunswick seaboard.

In January 1959, which is the base date for costs used in this report, the

cheapest fuel was Bunker C oil, at a cost of 35 cents per million Btu at the burner sa

Summary of Annual Charges - Annual charges described in the pre-

ceding paragraphs can now be listed for hydro-electric developments, and for new thermal-electric units, in terms of fixed and variable components.

Total annual charges for potential hydro-electric developments and for the

extensions of existing hydro-electric developments on the Saint John River, are given in Tables 27 and 28. Fixed annual charges for new thermal-electric units varying in size from 50 to 150 megawatts, installed in two-unit stations,

are given in Table 29. Variable annual charges for these units are given in

Table 30.

Fixed annual charges for the existing hydro-electric stations at

Grand Falls, Beechwood, Tobique, Musquash and Milltown, and for the thermal-

electric generating stations at Grand Lake, Chatharn and Saint John (Dock

Street), have been provided by The New Brunswick Electric Power Commission

and are $4,777,500 and $2,594,900 per year,. respectively.

Average costs for fuel and the variable component of operation

and maintenance at existing thermal- electric stations burning coal, are given

on Plate 5. TABLE 27

ANNUAL CHARGES FOR POTEN.TUL HYDRO-ELECTRIC DEVELOPMENTS ON THE SAINT JOHN RIVER

-~ Annual Charges - Millions of Dollars Plant Net Interest Depreciation, Operation Admini strat ion Name of Number Capability at 5. 5 Interim Replace- and and Development of Units Mw Per Cent ment, Insurancec Maintenance General Expense Total-72

Morrill 2 52.4 1.731 0.262 0.118 0.041 2. 152 3 75.7 1.947 0.296 0. 150 0. 053 2.446 4 98. 0 2.222 0.339 0. 180 0.063 2.804

Hawkshaw 2 72.7 2.485 0.366 0. 144 0. 051 3.046 3 105.7 2.739 0.406 0.189 0.066 3.400 4 136.7 3.029 0.452 0.241 0.084 3.806

Mactaqua c 4 223.6 5.203 0.689 0.365 0. 128 6.385 5 273.0 5.592 0.750 0.451 0.158 6.951 6 320.0 5.999 0.814 0.527 0.184 7.524 7 367.0 6.389 0.875 0. 601 0.211 8. 076 8 414.0 6.795 0.939 0. 668 0.234 8.636

!! These figures were computed as 0.86 per cent of estimated capital cost excluding flowage costs.

/2 Allowances for interest charges on unused substructures during the period of load buildup on each development were added to these figures in the system studies. ...

TABLE 28

. .. ANNUAL CHARGES FOR EXTENSIONS TO EXISTING HYDRO-ELECTRIC DEVELOPMENTS ON THE SAINT JOHN RIVER

Annual Charges - Millions of Dollars Number Net Inter e st Depreciation, Ope rat ion Admini str at ion Name of of Units in Capability at 5.5 Interim Replace- and and Development Extension MW Per Cent ment, Insurance!! Maintenance General Expense Total

Grand Falls Extension 2 82. 4 1.010 0.158 0.163 0. 057 1. 388 I 3 121.5 1.407 0.220 0.219 0.077 1.923 VI \D 4 159. 2 1.963 0. 307 0.289 0.101 2.660 I 5 195.0 2.359 0.369 0.357 0. 125 3.210

h 6 229.0 2.738 0.428 0. 425 0. 149 3.740

Beechwood Extension 1 31.5 0. 167 0.026 0. 097 0.034 . 0. 324 2 62.4 0. 628 0.098 0. 141 0. 049 0.916

!! The figures were computed as 0.86 per cent of estimated capital cost of extension. TABLE 29

FIXED ANNUAL CHARGES FOR NEW THERMAL-ELfEGTRLC UNITS IN NEW BRUNSWIGK

Annual Charges - Dollars Per Kilowatt Average for Additional Average for New Two-Unit Plants Component of Units at East Fixed Annual Saint John 50-Megawatt 75-Megawatt 100-Megawatt 150-Megawatt Charge Plant Unit .U$it Unit Unit

Inter e st, D epre cia- tion, Int'erim Re- placement and

Insurance - 7.18 1

D.. *. *. #. 12,06 11.44 11.03 10.66 per cent . . 9. 38 o\ 0 Interest on Reserve I Fuel . . e . . . . 0.10 0. 10 0.09 0. 09 0. 09

Fixed Operating Costs:

(a) Fuel OoO..OO.O. 1. 66 1. 66 1.52 1.49 1.44 (b) Operation and Maintenance 0. 56 2.20 1.76 1,38 0. 84 (c) Administration and General

Expenses o. 0.11 0.44 0.35 0. 28 0. 17

Total Fixed Annual

Charges .mv....o... 11.81 16.46 15.16 14. 27 13.20 TABLE 30

VARIABLE AN-NUAL CHARGES FOR NEW THERMAL-ELECTRIC UNITS IN NEW BRUNSWICK

Annual Charges - Mills per Kilowatthour Average for Additional Average for New Two-Unit Plants Component of Units at East Wariable Annual Saint John 50-Megawatt 75-Megawatt 100-Megawatt 150-Megawatt Charges Plant Unit Unit Unit Unit

Incremental Fuel

Cost 0 0 a 0 0 D 0 0 0 0 0 0. 3. 32 3. 32 3. 04 2.98 2. 88

Operation and

Maintenance . a . 0. 25 0. 25 0. 24 0. 23 0. 22

Total Variable Annual Charges . 3.57 -3.57 3. 28 3.21 3.10 4 - NOVA SCOTLA. ELGCTRIC UTILITIES INTERCONNECTED WIT& NEW BRUNSWICK

In 1960, interconnection will be established at 138 kv between the

,systems of The New Brunswick Electric Power Commission,. The Nova Scotia

Power Commission, and the Nova Scotia Light & Power Company Limited, in accordance with ar?.Agreement signed on November 18, 1959.

The important benefits to be derived by electric utilities through interconnection can broadly be classified into three groups:

(a] - The amount of generating capacity needed to meet the combined loads of the interconnected utilities is less than the aggregate capacity required in meeting these loads separately, assuming the same requirements for system reliability in all cases. Reserve capacity can be shared among the interconnected utilities and the total reserve can be made available under emergency conditions to any participant. The same considerations apply to spinning reserve. A related benefit is the ability to install larger units than would otherwise be possible.

(b) -As the total reserve capacity can be made available to any of the interconnected utilities in emergency, the location and distribution of spare capacity is of less consequence. Construction of new generating facilities can then be staggered in such a way that the amount of capacity in excess of total reserve requirements is held to a minimum at all times.

(c) - Energy can be interchanged between utilities to obtain the greatest possible utilization of available hydro- electric energy and capacity, and the economic loading of thermal- electric generation. - 63 -

The methods to be used in obtaining and sharing the benefits

described in (a) and (b) are fully defined by the Interconnection Agreement.

Provision is also made in this Agreement for energy interchange.

In determining the possible sequences of future power development in.New Brunswick, the benefits described in (a) aod (b) were taken

into account and two alternative conditions of energy interchange were

studied. In the first alternative, it was assumed that energy would not be interchanged except in emergencies. In the second alternative, it was

assumed that energy would be interchanged to give maximum economy,

as described in (c). These assumptions represent extremes of operation, and the actual operating prncedcres adopted in the future will prob-

ably lie between these two limits.

4. 1 - Generation

The nameplate rating and maximum two-hour capability of

generating facilities existing or under construction in 1959 by The Nova

'Scotia Power Commission and Nova Scotia Light & Power Company

Limited, are listed in Tables 31 and 32, and are summarized in Table

33.

The Nova Scotia Power Commission system consists 'of several

smaller systems or districts. The Canseau system on Gape Breton

Island and the Eastern Network on the mainland are commonly referred

to as the Eastern Network. Tusket and Mersey, together with the network TABLE 31

NAMEPLATE RATING AND MAXIMUM TWO-HOUR GROSS CAPABILITY

The Nova Scotia Power Commission Svstem - 1959

~ ~~ Hydr o - E lectr ic Stat ions Thermal- Electric Stations Maximum Maximum Nameplate 2-Hour Gross Nameplate 2-Hour Net Name of Rating Capability Name of Rating Capability Development Mw Mw Development Mw Mw

Eastern Network

I Barrie Brook . a 0. 36 0.380 Trenton D Dickie Brook . 3.80 2.480 Unit No. 1 . 10.0 9.559

Liscomb , a e a 0.45 0.490 2 .D.....0 10.0 10.102 I

Malay Falls . . #.-. . 3.60 3.325 3 .0....00 20.0 21.000 Ruth Falls. . . e a . . *. 6.97 7.265 4 OO..*._.. 20.0 21.000

15.18 13.940 Total e*OeD.OOD 60. 0 -61.661 Mersey System

Upper Lake Falls. o. 5.40 5.736(c) Lower Lake Falls . *. 7. 38 7.200

Big Falls *. e D. D.. . 9.00 9.600 Lower Great Brook. 4. 50 3.810

Deep Brook. m.. e. 9.00 9.030

Cowie Falls ,, a e a 7.20 8. 1'50

42.48 43.526 None Table 31 - 2

~~ ~~~ ~~ ~ ~-~ Hydr o -E lect r ic St at ions Thermal-Electric Stations Maximum Maximum Nameplate 2-Hour Gross Nameplat e 2-Hour Net Name of Rating Capability Name of Rating Capability D evelopment Mw MW Development Mw Mw

Note: Output of the Mersey System is supplied under contract to the Bowater's Mersey Pulp and Paper Company Limited and to the Western Network of The Nova Scotia Power Commission as follows: (a) - Supplied to Western Network - 10.62-mw nameplate 10.698-mw gross 2-hour capability (b) - Supplied to Mersey Pulp and Paper Company Limited - 31.86-mw nameplate 32.092-mw gross 2-hour capability (c) - Gross capability adjusted to 5.000 mw because of variable head.

Western Network

Gulch. D. e. a 6. 00 6.000

Ridge a a e 4. 00 3.800 Harmony. 0. 60 0.791

Roseway e 0. 89 0. 670 Sissiboo Falls . 6.00 6.000

Weymouth. e #. . . ., a 9.00 9.000 26.49 26.261 Western Network share of Mersey . 10.62 . 10. 698 Total Western Network 37.11 36,959 None

Tusket Svst em

Tusket Falls D. D. 2. 16 2.700 None Table 31 - 3

Hydro-Electric Stations Thermal-Ele ctric Stations Maximum Maximum Nameplate 2-Hour Gross Nameplate 2-Hour Net Name of Rating Capability Name of .Rating Capability Development Mw MW Development MW Mw

St. Margaret System

Mill Lake e. 2.56 2.500 Sandy Lake 3.20 3.200

Tidewater e a a a 4. 64 4.000 I

Total e.. 10.40 9.700 . None 6 6 I Note: The St. Margaret System is isolated from all other Nova Scotia Power Commission systems, but is tied .to. The Nova Scotia Light & Power Company Limited system at Halifax.

None Canseau System (Diesel)

Cheticamp e e . .'O 0.20 0,180 Ingonish a e o. *. -. e 0.77 0.600

Total . e . e 0.97 0.780 vote: These data have been extracted from the Interconnection Agreement. TABLE 32

NAMEPLATE RATING AND MAXIMUM TWO-HOUR CAPABILITY

Nova Scotia Light & Power Company Limited System - 1959

Hydr 0-Electric Stations Thermal-Electric Stations Maximum Maximum Nameplate 2-Hour Gross Nameplate 2-Hour Net Name of Rating Capability Name of Rating Capability Development Mw Mw Development Mw Mw AvonNo. 1 3.75 3.975 Water Street

Avon No. 2.. a De. -... 3.00 3,000 Unit No. 2 *. mo. 10.0 13. 000 Methals. ., -.. eo 3.40 3.400 3 .*..e... 20.0 19.838

Hollow Bridge D. 5.31 5.700 4 .O.OODOD 20.0 22.410 ,,.. I Lumsden *. . -.. . . *. 2.80 3.100 5 OaOO..Oo 25.0 28. 120 o\ Hells Gate No. 1 a *. 3.36 3.350 6 .OOOOeO. 45.0 47.815 41

2 DO.. 3.57 3.625 7 .0..*.0. 45.0 47.815 I

White Rock. a D. e 3.20 3.600 Y armouth

Nictaux ., Do *. 6.80 7.000 King Street (Diesel). 2.0 2.000

Paradise a'o o. 3. 60 5.100

Lequille a. ,, . o. o. 0. 18 0.100 Total.. . . *.. e 167.0 180.998 Bloody Creek. e -,e 0.35 0.200

Fall River. e 0.35 0.400

St. Croix . e 3.00 3. 150 Salmon Hole . . e . 2. 00 2.050

Total . -.o. 44.67 47.750

Note: (a) - The capability of six machines in the St. Margaret's Bay generating system is 10.40 megawatts of which 7 megawatts is purchasedby the Nova Scotia Light & Power Company Limited, (b) - Maximum 2-hour gross capability for thermal-electric stations has been reduced by station service requirements, to give net capability. (c) - These data have been extracted from the Interconnection Agreement. - 68 -

TABLE 33

SUMMARY OF NAMEPLATE RATINGS OF GENERATING STATIONS

The Nova Scotia Power Commission and Nova Scotia Light & Power Company Limited Systems - 1959

SUMMARY

Nameplate Rating - Megawatt System Hydro Thermal

The Nova Scotia Power Commission

Eastern Network , I) e a 15.18 60.00

Western Network e #. Do 26.49 - Western Network - Share of

Mersey ,, O.OO e Do Do.,o s.. 10. 62 Tusket System o. . - 2. 16

St. Margaret System a e 10.40 -

Canseau System D. e ., - - 0.97

Nova Scotia Light & Power Comnanv Limited 44.67 167.00

Total DoDo ., a 109.52 227.97 - 69 -

in the western part of the provincep are jointly referred to as the Western

Network. The St. Margaret's system serves the southwest part of Halifax

County. At the present the, each of the Eastern, Western, and St.

Margaret's systems has an interconnection with the Nova Scotia Light &

Power Company Limited, and in this way is indirectly interconnected elec- t r ically.

The Nova Scotia Light & Power Company Limited system serves the Halifax, Annapolis Valley, and Yarmouth areas, and part of the northern area of the province. Its hydro-electric stations are located in the Annapolis

Valley and its thermal units in the major load centre of Halifax.

With the exception of a potential 74-megawatt development at

Wreck Cove, most of the economic hydro-electric power resources in Nova

Scotia have now.'been developed, and it has been assumed by the Board that future load growth will be met by thermal power. Factors affecting the type, location, and cost of new thermal stations in Nova Scotia are similar to those which apply to New Brunswick and in the system studies described in this report, it was assumed that generation costs will be the same. It was further asswcned that the size of future thermal-electric units will be as large as can be economically utilized on the combined New Brunswick-Nova Scotia systems.

Details of unit sizes and generation costs for new thermal-electric plants in

New Brunswick are given in Section 3 of this report.

Complete basic information for existing generation and planned additions in Nova Scotia: was not available to the board in thefor its studies. - 70 -

Accordingly, the studies were limited to a consideration of energy interchange between The New Brunswick Electric Power Commission system and future generation of the two Nova Scotia utilities.

4.2 - LoadGrowth

The rate of load growth in Nova Scotia was of interest in the present studies, in that it may affect the timing of future generation in New Brunswick, the magnitude of installations at hydro- electric developments on the Saint John

River, and the extent to which the energy from these developments can be utilized in meeting the firm load demand. From information supplied by The

Nova Scotia Power Commission and the Nova Scotia Light & Power Company

Limited, the expected future load growth of these two utilities is the same as that which has been estimated for The New Brunswick Electric Power Commission system, namely, 9.4 per cent per year.

From the information available to the Board, it was not possible to estimate future trends in load factor for the Nova Scotia utilities, and it was assumed that load characteristics will remain approximately the same as those which are being experienced at the present time. The assumed monthly load duration curve for the interconnected load of the systems of The Nova

Scotia Power Commission and the Nova Scotia Light & Power Company Limited, is given on Plate 6, and assumed monthly demand factors from which the effect of load growth has been removed are given in Table 34. - 71 -

TABLE 34

ASSUMED MONTHLY DEMAND FACTORS FOR THE NOVA SCOTIA INTERCONNECTED LOAD

M onth’ly D emand Month Factors

January .DeOOOOeDDOOOD .955

February .OoOOODOmDO.D 883 March. * -. 852 April. e e e e -. .798 May ...... ,...... e 788

June ~.OOOOO.O.eO.OOOO .815

July.. Do e a a Do .792

August e Do .742

September e e e 812

October Do -. e 875 November ,, o. 9 933

December D. e 1.000 - 72 -

5 - TRANSMISSION

The existing transmission system of The New Brunswick Electric

Power Commission is shown on Plate 7, and consists of a network of lines at

69 kv with a limited 138-kv overlay. Over 1,100 miles of 69-kv transmission lines, developed over the years, cover the entire province and interconnect all of the existing generating stations. This transmission system supplies power to distribution points in both rural and urban areas.

Since 1957, an overlay of 138-kv transmission lines has been developed running between Beechwood, Fredericton, Grand Lake and Moncton.

Additional 138-kv lines are planned, or under construction, from Saint John to Fredericton, from Beechwood to Grand Falls, and from Grand Lake to

Bathur st. A single circuit 138-kv. interconnection between New Bruns-wick and Nova Scotia will be placed in service in 1960. In 1959, the existing 138- kv line from Grand Falls to Dalhousie was acquired by the Commission along with the Grand Falls plant. The 138-kv and 69-kv systems are interconnected through tie transformers located at Beechwood, Grand Lake, and Moncton.

Additional tie transformers are being installed at Fredericton and Saint John.

5. 1 - Network Analvzer Studv

A network analyzer study was made to determine the manner in which the transmission system of The New Brunswick Electric Power

Commission may be expanded over the next 20 years to meet the growing

power demands in the province, and to incorporate into the system the - 73 -

potential generation on the Saint John River. The first phase of the study was

a re-examination of the system to find whether or not the 138-kv voltage level

would continue to provide the most economic transmission. This was necessary

in the light of additional information which was available concerning tbe economy

of undeveloped power sites on the Saint John River. It was found that even if

the Passamaquoddy Tidal Power Project and the Rankin Rapids Auxiliary were

constructed, 138 kv would remain the most economic voltage level for trans-

mission within the province up to at least the year 1980. Thereafter, it may

' be necessary to construct an additional overlay at a voltage level of 230 kv or

higher.

The main portion of the analyzer study was concerned with finding

the transmission system required to give satisfactory performance for a

variety of conditions of load and combinations of generating facilities. A

number of basic requirements and assumptions were laid down for this work.

Assumptions as to load growth, unit sizes, transmission costs, and inter-

connections with Nova Scotia were as described in other sections of this re-

port. Additional assumptions and requirements were as follows:

(a) - That transmission in Maine associated with the Passamaquoddy and Rankin Rapids developments would be that which has been proposed by the International Pas samaquoddy Engineering Board.

(b) - That the conductor sizes for 138-kv and 230-kv transmission lines in New Brunswick would be 556,500 CM and 795,000 CM A. C. S.R, respectively.

(d) - That the minimum acceptable voltage at any load bus under conditions of line outage would b-e 95 per cent . of normal voltage.

(e) - That the distribution of load within New Bruhswick would be as given in Table.9.

The results of the network analyzer study can be illustrated by con-

sidering the way in which the transmission network of The New Brunswick

Electric Power Commission system may be expanded when generating facilities

are added in accordance with Sequence III( c) in which the Rankin Rapids develop-

ment is interconnected with the system of The New Brunswick Electric Power

Commission. The Rankin Rapids development is assumed to be commissioned

in the year 1968. The times at which additional generating facilities in New

Brunswick are added in this sequence are given in Table 35.

TABLE 35

SEQUENCE OF DEVELOPMENT IIl[(c)

Year Net Capa- of bility Commis- Development Type Mw s ioning

Existing System e *... a *. 256.2 -

Saint JohnNo. 1 .OD.DOOaOOOooDO.. Thermal 48,2 1961

Beechwood No. 3 *. a Hydro 31.5 1962

. SaintJohnNo. 2 .O.~OOOO.O.oOoOOo Thermal 72.5 1963 Grand Falls Nos. 1, 2, and 3 . . . Hydro 121.5 1966

,Mactaquac Nos. 1 and 2 a a a Hydro 115.0 1970

Mactaquac Nos. 3 and 4 L1 a a - Hydro 108.6 1972

Mactaquac Nos. 5, 6, 7, and 8 .O. Hydro 190.4 1974 Grand Falls Nos,, 4, 5, and 6.. . e -. Hydro 107.5 1976 Morrill Nos. 1, 2, 3, and 4.. -. Hydro 98. 0 1977 Bathurst No. 1.. a -.o. e a Thermal 143.4 1978 Bathurst No. 2. Do e Do. . Thermal 143.4 1980 - 75 -

The existing transmission system has already been described and is shown on Plate 7. En Sequence IIEQc), two thermal units will be installed at the East Saint John thermal plant, and a third unit will have been installed at the Beechwood development by the year 1963. The transmission network which will be required at that time is shown on Plate 8, additional 138-kv lines being required between Grand Falls, Beechwood and Fredericton, and between Grand Lake and Bathurst. These lines are either under construction or are planned.

From 1963 to 1968, further transmission lines will be required as can be seen from Plate 9, which shows probable conditions in 1968. In this period, a second 138-kv interconnection with Nova Scotia has been included, together with a second line from Grand Falls to Dalhousie and from Fredericton to Grand Lake to Moncton. Double-circuit 138-kv lines from Beechwood to

Presque Isle, Maine, will be constructed as required in Sequence IIICc) to interconnect The New Brunswick Electric Power Commission system with

Rankin Rapids.

By the year 1974, the Mactaquac development will be installed to its ultimate capacity of eight units in Sequence III(c), and an additional double- circuit 138-kv transmission line will be required from Mactaquac to Fredericton as shown on Plate 10. From 1975 to 1980, additional lines will be needed from

Beechwood to Grand Falls, and from Grand Lake to Newcastle to Bathurst.

Plate 11 'shows the probable transmission network in 1980 under Sequence

In(c) 0 - 76 -

Additions to the transmission system are needed primarily as a result of increased load demand over the entire system rather than the construction of any specific generating facility. For this reason the development of the transmission network, as has been described for Sequence III( c), is typical and can be applied with minor changes to all other sequences which have been considered.

5.2 - Costs

All estimates of capital cost and annual charges associated with the transmission network were based upon the experience and current practice of The New Brunswick Electric Power Commission in economic studies.

The estimated capital costs at January 1959 prices for transmission lines, transformation and switching are given in Table 36.

TABLE 36

CAPITAL COSTS OF TRANSMISSION AND TERMINAL FACILITIES IN NEW BRUNSWICK

Voltage It em 138 Kv 230 Kv

A. C. S, R. Conductor Size e 556,500 CM 795,000 CM

Capital Cost: (Steel Tower Construction)

(a) - Single circuit e *. $ 25, 000 mile (b) - Double circuit o. e a $ 40, 000 mile $ 55,000 mile

Transformation a a e e $3. 00 per kva $3.00 per kva

Swi€ching o. e ., e e $125,000 per $200,000 per element e 1em ent

Note: Transformation prices are based on transformer sizes of 50 mva and larger. Switching costs are based on a "breaker and one-half" arrangement. - 77 -

In determining the annual charges associated with transmission lines, transformation and switching, the Board has used an interest rate of

5.5 per cent. As it was assumed that all future transmission lines will be

of steel tower construction, the economic life of these lines and of the associ-

ated transformation and switching, was taken as 40 years. The sinking fund

interest rate was assumed to be 4-1/2 per cent. On this basis the total figure

for interest and depreciation amounts to 6.43 per cent.

Operation and maintenance charges for transmission lines and

terminal facilities vary with the type of transmission line and with voltage.

Estimated operation and maintenance charges for transmission lines are given

in Table 37, and for terminal facilities in Table 38.

TABLE 37

ANNUAL OPERATION AND MAFNTENAWCE CHARGES - TRANSMISSION LINES - N, B. E. P. C, SYSTEM

Ope rat ion and Maintenance Charges - Dollars Per Mile Type of Line 138 Kv 230 Kv

Single Circuit - Steel Tower -. e 170 -

Double Circuit - Steel Tower e 220 320 - 78 -

TABLE 38

ANNUAL OPERATION AND MAINTENANCE CHARGES - TERMINAL FACILITIES - N. B. E. P. C. SYSTEM

Terminal Operation and Maintenance Station Charges - Dollars Per Kva Capacity - Mva Sending; Station Receiving Station

50 0. 69 0.75 100 0.37 0.40 200 0. 29 0. 32

Annual charges for head office administration and general expenses associated with transmission lines and terminal facilities, were taken as 20 per cent of the operation and maintenance costs given in Tables 37 and 38.

The unit costs and annual charges were used in the studies to determine the total annual charges year by year associated with the transmission network in each sequence of development. The manner in which annual charges for transmission and terminal facilities will increase in the future can again be illustrated by considering Sequence III(c). Various

stages of expansion of the transmission network required in this sequence,

are shown on Plates 8, 9, 10, 11, and the annual charges for transmis-

sion and terminal facilities at these various stages are given in Table 39. - 79 -

TABLE 39 ..

ANNUAL CHARGES FOR TRANSMISSION AND TERMINAL FACILITIES IN SEQUENCE III( c)

Annual Charges Year Million Dollar s

1960...... 3.15 1963...... 4.00 1968...... 4. 60

1974. os oa moe oa mv 4,74 1980...... 5. 38

Note: The above figures do not include annual charges associated with transmission in Nova Scotia and Maine.

~ ~ ~ ~~~ ~~~~~~ ~~ ~~

Additional transmission facilities which will be required in New

Brunswick over the next 20 years are not extensive and the associated annual charges will become quite small in relation to annual charges for generation. Therefore, the effect of small variations in the transmission network on the results of the studies described in this report will be negligible.

Annual charges for the existing transmission network and terminal facilities in New Brunswick, as provided by The New Brunswick

Electric Power Commission, are $2, 928, 300. - 80 -

6 - THE PASSAMAQUODDY TIDAL POWER PROJECT

At a meeting of the.Internationa1 Joint Commission on October 3,

1956, the International Passamaquoddy Engineering Board was established to determine the estimated cost of developing the international tidal power potential of Passamaquoddy in the State of Maine and the Province of New

Brunswick, and to determine whether such cost would allow hydro- electric power to be produced at a price which is economically feasible. The results of this study were presented by the International Passamaquoddy Engineering

Board in a report dated October 1959, from which the information given in this section has been extracted.

A two-pool type tida1,project was selected as being best suited to the site conditions which exist at Passamaquoddy and Cobscook Bays and the power markets which such a development would serve. The project will involve construction of nearly seven miles of rock-filled dam, 90 filling gates and 70 emptying gates, each 30 feet wide by 30 feet high, four navigation locks, two of which would be 415 by 60 by 21 feet and the other two 95 by 25 by 12 feet, and a powerhouse containing 30 units rated at 10, 000 kw each.

The estimated capital cost of the Tidal Project, excluding interest during construction, is 484 million dollars.

This estimate is based upon a six-year construction program . . preceded by a two-year period to allow for design, purchase of major equipment, and the award of contracts for construction. If approval for the project - 81 -

were to be obtained in 1962, it would.then be possible to produce first power from the development in the year 1970.

As explained under Section 1.2 - Scope of Study, the Passamaquoddy

Tidal Power Project, although uneconomic for Canada at the present the, is nevertheless economically justified if built entirely by the United States at an interest rate of 2-1/2 per cent. The effects of possible variations in the control of Rankin Rapids storage, when operated to firm up output from the Tidal

Project, have, therefore, been considered in this report.

The average year energy, which can be generated by the proposed

Tidal plant when operated for maximum energy output, was estimated to be

1, 898 million kilowatthour s. When various adjustments are applied for hydraulic losses, project power use, scheduled outages, etc., this value is reduced to 1, 843 million kilowatthours.

The Tidal plant would normally be operated to extract the maximum energy from each tide cycle, giving a peak output equal to, or greater than,

82 megawatts for 98 per cent of time. However, by sacrificing small quan-

.tities of energy, and modifyiag the operating procedures at times when the peak demand coincides with minimum output from the Tidal Project, it would be possible to increase this figure to 95 megawatts.

In all of the studies described in this report, it has been assurned that the dependable capacity of the proposed Passamaquoddy Tidal Power

Project would be 95 megawatts and that mean monthly energy outputs would vary in accordance with the figures given in Table 40. These figures were - 82 -

computed by the International Passamaquoddy Engineering Board, and represent the mean monthly energy outputs corresponding to tidal conditions for the year 1937.

TABLE 40

MEAN MONTHLY ENERGY OUTPUTS

Passamaquoddy Tidal Power Project

Output in Million

Month Kilowatthour s -d

January ...... e 154

February .ea ..O m.. 141

March.. . . Do 157

April. o.. 151

May. ., Do Do - - 155

June .OO.oODOODD... 153

July. a 161

August . . e . 161

September . ., D. 156

October o. a. e 161 November . -.. 151 December 153

Total. so-. . . . 1,854

Note: The annual energy output of 1 854 million kilowatthour s is slightly in excess of the long term mean figure quoted in the text. - 83 -

When operating for maximum energy, there will be considerable variation in output from day to day and lesser variations from week to week, month to month, and from year to year. The range of these variations as computed by the International Passamaquoddy Engineering Board are given in Table 41. Power output from the Tidal Project will vary from the dependable output of 95 megawatts to the maximum plant capability of 345 megawatts.

TABLE 41

VARIATION IN ENERGY OUTPUT

Passamaquoddy Tidal Power Project

Energy Output Million Kilowatthour s Time - ht e r val Minimum Mean Maximum

Day oo ooDo~ooooD oo 2.3 5.0 7. 6 Week . ., 20.5 35.2 49.7

Month Do e 131 154 170

Year a 1,738 1,843 1,923

The variation in energy output of .the Tidal Project from year to

year is small as can be seen from the figures in Table 41 and, in all of the

system studies described in this report, the annual output has been assumed

to be constant and equal to the estimated figure for the year 1937, namely)

1, 854 million kilowatthours. This figure is slightly greater than the average

year output, nam,ely, 1 843 million kilowatthour s. Actual computations in - 84 -

the system studies of the Saint John River Board were carried out for each month of a 20-year period of flow record on the Saint John River, and the variation in monthly energy output from the Tidal Project as given in Table

40 for the year 1937 was used.

. As monthly intervals were used in the system studies, it was not possible to examine in detail the effect on Grand Falls forebay of hourly fluctuations in flow from Rankin Rapids when utilized to firm up the output of the

Tidal Project. Approximate calculations were made, therefore, to estimate

the magnitude of these fluctuations under extreme conditions e

Plate 14 of the International Passamaquoddy Engineering Board report dated October 1959, gives typical hour-by-hour operation for a three- week period when the Tidal Project and the Rankin Rapids Auxiliary are operated with other generation to meet a peak load of approximately 1, 600 megawatts at 60 per cent load factor. On Wednesday of the second week, operation of the Tidal Project is reduced to the dependable output of 95 megawatts resulting in severe fluctuations in output from Rankin Rapids. The outflow hydrograph for this day as computed by the Internztional Passamaquoddy

Engineering Board, was routedthrough the reach of the Saint John River from

Rankin Rapids to the existing Grand Falls plant, giving an estimated fluctuation of one foot in the Grand Falls headpond, Th'ese calculations must be regarded as approximate, as river cross sections available to the Board extend only to the upstream end of the Grand Falls headpond, and cross sections from there to the Rankin Rapids site are not available. - 85 -

In the system studies described in this reportl it was found that extension of the Grand Falls plant to provide peaking capacity in New

Brunswick is economic. Howeverp it may be possible for headpond draw- downs consequent upon resulting fluctuations in inflow from Rankin Rapids and from peak load operation of the Grand Falls plant, to coincide, and the capacity of the Grand Falls headpond may not be sufficient for both purposes.

Whether or not this will actually be the case can be determined only by detailed computer studies on an hourly basis. It was considered unnecessary to make such studies at the present time. - 86 -

7 - SYSTEM STUDY PROCEDURES

The benefits of using digital computers in system studies are now being recognized to an increasing extent by electric utilities. However, the majority of computer programs described in technical literature deals with economic loading of generating stations and, in particular, thermal-electric stations, on an hour-by-hour basis. The system studies undertaken by the

Board were much broader in scope and dealt with the long term economy of potential generation on a mixed hydro-electric and thermal- electric system.

A considerable amount of development work was required, and it is believed that the program which was produced represents an advance in

.the science of system planning. The program utilized the entire 8, 000-word memory and several tape units of an IBM 704 computer.

7.1 - ScoDe

The scope of the computer program was governed by the manner in which the Saint John River Board interpreted those parts of the Terms of

Reference related to power generation, as described in Section 1.2. The

sequences of development which were studied in detail involve three power

system-s, narnely, the system of The New Brunswick Electric Power Commission, future load and generation on the combined systems of The Nova Scotia Power

Commission and the Nova Scotia Light & Power Company Limited, and a power

system in Maine incorporating the Passamaquoddy Tidal Power Project and the

Rankin Rapids Auxiliary. The computer program was required to simulate - 87 -

these systems both individually and inany combination. A major problem arose in the system simulationbecause the firm power output from power developments on thesaint John River in New Brunswick was governed in the early stages of some sequences bylowflow conditions onthe river. Both the energy and power output from all power developments were therefore matched against the system load curve month by month to give an accurate determination of firm power output, taking into account the shape of the load curve, especially around the time of peak load demand.,

In the first part of the program, the load duration curves for the systems being consideredare addedto give a combined load curve, from which the predetermined outputs from the Musquash and Milltown developments of

The New Brunswick Electric Power Commission and from the proposed

Passamaquoddy Tidal Power Project are subtracted when applicable. The residual load curve must .then be met by hydro-electric developments on the

Saint John River and by thermal-electric plants.

In .the next section of .the program, a rule curve for the controlling reservoir or group of reservoirs onthe Saint JohnRiver or its tributaries is computed to ensure reliable operation of the system and, if necessary,, the load demand is reduced to the maximum value which the system is capable of meeting, The rule curve computations take account of minkmum flow requirements at hydro-electric developments, assumed to be 1, 000 cfs at the

Beechwood, Hawkshaw andMactaquac developments and 200 cfs at the Tobique development - 88 -

The main section of the computer program can simulate all of the three power systems combined, this being the largest total system which it was necessary to consider in the sequences of development. Individual systems

are simulated by suppressing or equating to zero all generating stations and

storages not included in the system under study. A special section of the pro-

gram enables outflows from the Rankin Rapids development to be printed out

or stored on magnetic tape during runs dealing solely with a power system in

Maine incorporating the Rankin Rapids development,

The output from hydro-electric stations on the Saint John River

and from thermal-electric stations is computed during the system simulation, using a plant directory which has provision for onevariable headand six con-

stant headhydro-electric developments, together with six individual or grouped

thermal-electric developments. The plant directory can be used to simulate

generating stations of any of the three systems considered. In the studies which were made, the variable head hydro-electric development was Rankin

Rapids, and the six constant or near constant head developments were the

downstream plants on the Saint John River and at Tobique Narrows. All

important plant characteristics such as tailwater rating curves, efficiency

curves, curves of flow versus potential output, the capacity of thermal-

electric plants, etc., are stored in the computer me-mory and utilized in

this section of the program.

Storages intheSaintJohnRiver basinare classified into groups,

andthe entire live storage volume of each groupwas assulmedtobe located - 89 -

at the storage site in that group which is furthest downstream. This method of approach is correct, provided every storage in each group can be refilled each year, and that no hydro-electric developments exist between the storages, as was the case in all sequences considered by the Board.

The program contains provision for four storage groups, namely:

Group 1 - The Rankin Rapids development and all storages upstr eam

Group 2 - Storages between .the Rankin Rapids and Grand Falls developments

Group 3 - Storages on the Tobique River.

Group 4 - Storages on the Aroostook River.

A ZO-year period of flow record on the Saint JohnRiver, from

October 1932 to September 1952, was chosen for use in the power and energy

computations as described in Section A4.2 of the Appendix. During this period,

coincident records were available for gauges at Pokiok, Grand Falls and Fort

Kent, on the Saint John River, and for gauges at Washburn on the Aroostook

River, Ste. Rose du Degele on the Madawaska River, and near Fort Kent on the

Fish River. Monthly flows recorded at these gauges were first adjusted to natural flows as required, and supplied as input data to the computer. Ratios by which the uncontrolled runoff at all storage and power sites in the river can be calculated from these natural flows, as described in Section A4.2 of the

Appendix, were also supplied as input data. Power and energy computations were made for each month of the 20-year period of record. - 90 -

Fixed annual charges for generation and transmission can be easily calculated by hand for any set of system conditions. However, the computation of variable annual charges at .thermal-electric stations is more complex and was handled in a special section of the computer program, an appropriate curve giving energy, operation, and maintenance costs being supplied as input data. These variable annual charges for the 20-year period of record were averaged and added to the fixed annual charges to give the total annual charges used in the comparison of sequences of development,

7.2 - System Operating Criteria

Operating criteria used in the system studies and incorporated in the computer program are designed to keep spillage at hydro-electric developments to a minimum while controlling storage in accordance with predetermined rule curves which ensure 'adequate system reliability.

The reliability of electric utility systems throughout Canada is usually high, and substantial expenditures are made to ensure continuing service except under most unusual or unforeseen circunstances. Comparatively stringent requirements for reliability were therefore adopted in the system

studie s.

As probability studies dealing with the outage of generating units were not made, it was conservatively assumed that a minimum of 15 per cent spare capacity will be required on the systems which were studied., It was further assumed that any system must be capable of meeting the load demand - 91 -

if the lowest flows on the Saint John River during the 42-year period of record at the Pokiok gauge are experienced.

From an examination of computed natural flow for this gauge, it was found that the increase in river flaw at breakup occurs fairly quickly and is sufficient to allow filling of storage reservoirs to begin in April, as is illustratedbythe figures inTable 42. Inthe system studies, it was assumed that the spring flood of each year starts on April 1. It was then permissible for all storage reservoirs to be emptied by March 31. In practice, some storagemaybeheldinreserve after March 31 to guard againstthepossibility of a late arrival of the spring runoff.

TABLE 42

LOW APRIL FLOWS AT POKIOK GAUGE, WITH FLOWS FOR THE PRECEDING MARCH, SELECTED FROM THE PERIOD 1932 TO 1952

Natural Average Monthly Flows - Gfs Year March April

1933 3,570 53,500 1937 8,280 53,300 1939 6,130 31,900 1940 5, 070 48, 900 1943 4,760 22,200 1944 2,800 14,200 1947 12,800 46,000 1948 5, 620 50,400 - 92 -

The lowest flow conditions which have been experienced on the

Saint JohnRiver at Pokiok, are listed in Table 43 which gives accumulated natural flows from each month to the following March 31. For example, the minimum accumulated flow at the Pokiok gauge from January 1 to March 31 occurred in the year 1944 and amounted to 10,530 cfs-months. The natural monthly flows for .the Pokiok gauge as used in the rule curve calculations, are the differences between. these minimum accumulated flows of record.

They represent flows for an artificial year for which the total annual runoff is less than has been recorded for any one year.

Natural flows for the same months, for the gauges at Grand Falls and Fort Kent on the Saint John River, at Washburn on the Aroostook River, at Ste. Rose du Degele on the Madawaska River, and near Fort Kent on the

Fish River, were used to establish flows at these locations for the artificial year used -$I the rule curve calculations as given in Table 44.

For any given set of system conditions, one of the groups of

storages listed in Section 7. 1 was selected as the controlling storage, all

other storage groups being operated in accordance with a set of predetermined rule curves of the type shown on Plate 12. The rule curve for the controlling

storage was calculated in the computer program using the criterion that it should

always be possible to meet th’e power demand on the system w’ith thermal plants base loaded and with the monthly river flows for the artifical year.

If too high a load demand is supplied to the computer, the rule curve

calculation shows that there is insufficient live storage available to enable the TABLE 43

MINIMUM ACCUMULATED NATURAL FLOWS AT THE POKIOK GAUGE

Year - April May June July Au.g S ept 0 ct N ov Dec Jan Feb Mar Accumulated Natural Flows to March 31 - Cfs-Months

1944- 45 219,190 204,890 141,490 124,890 115,320 108,390 101,380 73,780 48,880 39,040 24,640 16,700 1921-22 153,200 114,100 105,080 100,070 87,770 80,670 56,970 4OP 670 27,670 18., 310 12,900 1942-43 86,470 51,070 38,470 33,940 31, 040 25, 160 16,690 11, 310 8, 110 4,760 , 1947-48 32,140 26,430 22,440 17,270 12,790 8,370 5,620 1942- 43 16,690 11,310 8,110 4,760 1944 10,530 5,510 2,800 '

Mini.mum accmulat ed flows of record 219, 190 153,200 86,470 51,070 38,470 32,140 26,430 22,440 16,690 10,530 5,510 2,800

Natural Monthly Flows for Rule Curve Calculation

Artificial year 65,990 66,730 '35,400 12,600 6,330 5,710 3,990 5,750 6,160 5,020 2,710 2,800 TABLE 44

N.ATURAL MEAN MONTHLY FLOWS AT ALL GAUGES FOR THE ARTIFICIAL YEAR AS USED IN THE RULE CURVE CALCULATION

Flow - Cfs Gauge River April May June July Aug Sept Oct Nov Dec Jan Feb Mar

Pokiok Saint John 65,990 66,730 35,400 12,6QO 6,330 5,710 3,990 5,750 6, 160 5,020 2,710 2,800

I GrandFalls SaintJohn 28,214 40,136 20,600 7,560 4,900 3,570 2,840 3,800 2,630 2,040 1,090 1,150 P .. Fort Kent Saint John 23,700 24,000 13,400 4,541 4,528 2, 127 1,578 1,411 1,450 1, 185 790 669 I

Washburn Aroostook 7, 650 7,737 3,823 773 1,724: 369 io3 478 242 416 152 io4

Ste. Rose du Degele Madawaska 1,867 5, 692 2,880 960 414 307 480 436 409 246 298 260

Near Fort Kent Fish 3,290 3,330 2,156 943 172 219 134 305 292 210 164 107 - 95 -

base loaded thermal-electric plants and peak loaded hydro-electric plants to

meet the load demand. Under these circumstances, the load demand is auto-

matically reduced by steps to a value which can just be met. This figure is

then the low flow dependability of the system being coosidered.

The rule curves used ~IIthe system studies give the minimum

volumes of live storage which must be available during each month of the year

if the low flow dependability of the system is to be maintained. They there-

fore represent the lowest limits to which storage should be drawn in each

month. The operating criterion used in the system studies for the control of

storage was that every attempt should be made to draw down storages as

quickly as possible to the rule curves by base loading hydro-electric develop-

ments, so that the reservoirs can receive and store the maximurn possible

volume of water from any flood which may subsequently occur. Once the rule

. curve is reached, storage can then only be withdrawn as allowed by the rule

curve (I

These procedures for the control of storage on the Saint John River

were follo-wed throughout the studies except at the Rankin Rapids storage and

power development when operated integrally with thermal-electric generation

in Maine. In this case, the procedures would not necessarily result in the

maximum production of at- site hydro-electric energy, as reservoir elevations

would, in some months, be lower than is actually necessary for maximum

control of river flow. This was overcome in the computer program where

necessary, by first determining the optimum rule curve for at-site energy - 96 -

production by varying the proportions of thermal-electric generation on .the system in Maine, and using this rule curve in subsequent studies.

There are two special problems which arise when considering a series of hydro-electric developments on one river. The first involves a condition in which one of the generating stations has a low flow capacity in relation to the others. Water from storage may have to be spilled at the station with’ the low flow capacity to allow the full capacity of other stations to be utilized in meeting the load demand. This type of spillage was termed Type A and was automatically allowed by the computer program when required..

The second problem is somewhat similar, in that it involves a hydro-electric development of relatively low flow capacity in relation to other developments on the river. It may sometimes be economical to increase the release from storage and to spill water at such a station to reduce thermal- electric energy generation. Water spilled in this manner is termed Type B spillage and was found to be essential for maximum hydro-electric energy generation in some computer runs.

The criteria which have so far been described relate to the control of storage to ensure system reliability and to keep spillage at hydro- electric developments to a minimum. However, the distribution of load demand among hydro-electric developments on.the Saint John River is also of importance in keeping spillage to a minimum and criteria were established for this purpose. For each condition of loading among hydro-electric and thermal-electric stations, the ratio of energy output to net capability far each - 97 -

hydro-electric station on the Saint John River was calculated. These ratios,

or stacking factors, were then used to determine the order in which .the hydro-

electric stations should be placed on .the load curve to ensure minimum spillage, the plant with the highest stacking factor being placed on the load curve first,

All of the operating criteria described above are based upon the assumption that the transmission network will be adequate to handle the sub-

stantial variations in power output obtained from the hydro- electric and thermal-

electric generation stations of the system.

The important operating criteria and assumptions used in the computer program, as described above, can be summarized as follows:

A minimum of 15 per cent, spare capacity will be required on all systems which were studied.

Rule curves were established for all secondary storages and a rule curve was computed for the primary storage on the Saint John River and its tributaries to ensure that the system will be capable of meeting .the load demand, if the lowest flows during the 42-year period of record at the Pokiok gauge are again experienced. The rule curve for storage at the Rankin Rapids development was chosen for maximum at- site energy generation as well as for system reliability.

Subject to the limitations imposed by these rule curves, water was normally withdrawn from storage at the maximum rate possiblf: without spillage at hydro-electric developments downstream.

Spillage of stored water at a downstream development was allowed in special circumstances when it was necessary in meeting .;the system power - 98 -

demand (Type A spillage), or when by so doing, the overall energy requirement from thermal-electric stations could be reduced (Type B spillage),

(e) - The transmission network will, at all times, be adequate to handle the substantial variations in operating conditions created by following these criteria.

7. 3 - Input Data

The majority of data used in the system studies has already been described in preceding sections of this report and is now summarized for convenience of reference. The symbols are consistent with .those used on the computer input sheets. Basic data for the studies can broadly be divided into the following sections:

I.D. - S - System Load Characteristics

I.D. - P - Generating Station and Storage Reservoir Characteristics

I.D. - R - Rive.r Flow Records and Drainage Area Ratios

I.D. - 0 - Operating Rules

I.D. - M - Cost Information.

The input data included in each of the above sections are listed in Tables 45, 46, 47, 48, and 49, together with references to the tables or plates in which the information has been recorded in this report or its appendix. - 99 -

TABLE 45

INPUT DATA - SYSTEM LQAD CHARACTERISTICS

Svmbol De s crintion Reference

I.D, - S - 1B Annual firm peak demand on the system of Var ies with The New Brunswick Electric Power each run. Commission.

I. D, - S - 1s Annual firm peak demand for incremental Varies with load in Nova Scotia. each run.

I. D. - S - 1M Annual firm peak demand of a utility in Varies with Maine. each run,

I.D. - S - 2B Monthly demand factors for the system Table 8 of The New Brunswick Electric Power C ommis s ion

I.D. - S - 2s Monthly demand factors for incremental Table 34 load in Nova Scotia.

I. D. - S - 2M Monthly demand factors for a partial . Table 56 system in Maine.

I.D. - S - 3B Monthly load duration curve for the system Plate 4 of The New Brunswick Electric Power Commission.

I.D. - S - 3s Monthly load duration curve for incremental Plate 6 load in Nova Scotia.

I. D. - S - 3M Monthly load duration curve for a utility in Plate 19 Maine - 100 -

TABLE 46

INPUT DATA - GENERATING STATION AND STORAGE RESERVOIR CHARACTERISTICS

Symbol D e s c r ipti on Reference

I.D. - P -. 1 The capacity of all thermal plants included Varies with in the system. each run.

I.D. - P - 3 ) Flow capacity curves for hydro-electric I.D. - P - 11) stations on the Saint John River and for the Tobique station:

Grand Falls Development -

Flow Capacity Curves e e a Plate A30

Tobique Development - Flow Capacity Curves a e e Plate A34

Bee chwood Development -

Flow Capacity Curves D. e Plate A37

Rankin Rapids Development -

Flow Capacity Curves a Do a Plate A38

Pr op o s ed Morr ill D evelopment -

Flow Capacity. Curves e a e e e ., Plate A50

Propo s e d Hawkshaw D eve1opm ent - Flow Capacity Curves a e Plate A58

Proposed Mactaquac Development -

Flow Capacity Curves ., a Plate A69

I.D. - P - 4 Average monthly output for the Milltown hydro- Table 12 electric development in New Brunswick.

I.D. - P 5 Average monthly output for the Musquash Table 11 hydro-electric development in New Brunswick. Table 46 - 2

Symbol D e s cr ipti on Reference .

I. D. - P - 6 Average monthly output for the Pas,samaquoddy Table 40 Tidal Power Project,

I. P. - P - 7 Percentage reductions in head due to forebay Table 17 drawdown.

I.D. - P - 8 Reservoir storage capacity curves:

Temiscouata Lake - Area and

Capacity Curves a e e o.o Plate A22

Lac Squatec Reservoir - Area and Capacity Curves ., - Plate A23

Long Lake - Area and Capacity Curves ., ,, a Plate A24

Ledges Reservoir - Area and Capacity Curves .. ., Plate A25

Glazier Lake - Area and

Capacity Curves ., ., e e (I Plate A26

Masardis Reservoir - Area and

Capacity Cu-wes o.ooDDooo~~olooooDDo~~~Plate A27

Rankin Rapids Development - Area and Capacity Curves of Headpond ., ., Plate A40

I.D. - P - 9 Tailwater rating curve for Rankin Rapids. Plate A39 - 102 -

TABLE 47

INPUT DATA - RIVER FLOW RECORDS mDDRAINAGE AREA RATIOS

Symbol De scription Reference

I. D. - R -. 1 Natural monthly flows from October 1932, to September 1952, for the following gauges:

Saint John River below Fish River at

Fort Kent, Maine Do Do e ., a Table A8

Saint JohnRiver at Grand Falls,

New Brunswick ,,Do ,, e D. Table A9

Saint John River at Pokiok,

New Brunswick e e e o. Table A10

Fish River near Fort Kent, Maine e - Table All

Madawaska River at Ste, Rose

du Degele, Quebec e ., e a Table A12

Aroostook River at Washburn, Maine ., Table A13

I.D. - R - 2 Ratios by which the uncontrolled runoff at hydro-electric and storage sites in the Saint John River basin were calculated from the flow records described above. Section A4

I.D. - R - 3 Natural mean monthly flows at all gauges for the artificial year as used in the rule curve calculations Table 44 - 103 -

TABLE 48

INPUT DATA - OPERATING RULES

Symbol D e s c F iption Reference

I. D. - 0 - 1 The amount of Type B spillage allowed per Var ies with

month. ' eachrun.

I. De - 0 - 2 Minimum flow requirements at hydro- electric stations. Section 7. 1

I.D. - 0 - 6 Rule curves for auxiliary storages. Plate 12 ( Typica1 curve),

TABLE 49

INPUT DATA - COST INFORMATION

Symbol Description Reference

LD, - M - 4 A curve showing the incremental fuel cost Plate 5 and the variable portion of the operation (Typical and maintenance plotted against the peak curve) power output from thermal stations, in ascending order of cost. - 104 -

7.4 - Output Data

The choice of output data obtained from each run of the computer was influenced, on the one hand, by the desire to have as much information

as possible and, on the other, by the need to keep the time and cost of the

computer work and the volume of output within reasonable limits.

Accordingly, it was decided to write the program in such a form that average, minimum, and maximum values for the 240-month period, or

individual monthly figures, or both, could be obtained for any run as desired.

In the majority of runs, only the annual average, minimum and maximum values of such important functions as power output, energy output, spillage,

and costs were obtained, using the on-line printer. Where detailed monthly

output was required, it was recorded on tape and printed off-line. Outputs

obtainable in the two categories described above are listed in Tables 50 and

51.

The primary figures obtained from each computer run were the

variable annual charges for all thermal-electric stations on the system.

These annual charges were added to the fixed annual charges for the hydro-

electric and thermal-electric stations and for the transmission network, to

obtain the total annual charges for the system at the points of distribution.

Estimates of load demand given in this report represent net de-

mand at the generator terminals. The computed energy output was reduced

by four per cent to allow for transformation and transmission energy losses. - 105 -

TABLE 50

OUTPUT DATA - ANNUAL AVERAGE, MINIMUM, AND MAXIMUM VALUES FOR THE 240-MONTH PERIOD

Item No. Description

1 A repeat of input data.

2 The annual peak demand which was tested.

3 The rule curve for the pr4xnary storage or group of storages.

4 The total incremerrtal fuel and variable operation and maintenance cost for all thermal stations.

(a) - A 20-year average. (b) - Maximum annual value for t.he 20-year period. (c) - Minimum annual value for the 20-year period.

5 The total. energy generated by all .thermal stations and by the stations individually

(a) - A 20-year average. (b) - Maximum annual value for the 20-year period. (c) .= Minimum annual valxie for the 20-year period. (d) - Maximum msnthly value for the 20-year period. (e) - Minhcm mol.;thly value f~rthe 20-year period.

6 The total energy generated by all hydra st.ations and by the stations individually (a) - A 20-year average. (b) - Maximum annual value for the 20-year period. (c) - Minimum annual value for the 20-year period. (d) - Maximum monthly value for the 20-year period. (e] - Minimum :monthly yd?-uefor the 20-year period.

7 A 20-year average ~f total flood spillage at all hydro. stations and at the stations individually.

8 A 20-year average of total Type A spillage at all hydro stations and at the stations individually. - 106 -

Table 50 - 2

Item No. Description

9 A 20-year average ot total Type B spillage at all hydro stations and at the stations individually.

10 A 20-year average of total potential secondary energy generation at all hydro-electric stations and at the statiolzs individually.

11 Average values of thermal energy and capacity generation over a 20-year period, for each month of the year9 under conditions of base load and of peak load operation.

TABLE 51

OUTPUT DATA - MONTHLY VALUES FOR THE 240-MONTH PERIQD

Item No. D e s c r iption

1 The total incremental fuel and variable operation and maintenance cost for all thermal stations.

2 The total energy generated by all thermal stations and by the stations individually.

3 The total energy generated by all hydro stations and by the stat ions individually.

4 Total flood spillage at all hydro stations and at the stations individually.

5 Total Type A spillage at all hydro stations and at the stations individually.

6 Total Type B spillage at all hydro stations and at the stations individually

7 Total potential secondary energy generation at all hydro . . . :. stations and at the stations individually. - 107 -

The computed annual charges for each run were divided by the resultant load energy to obtain the estimated cost of energy at distribution points.

7.5 - Simplified Flow Charts

The methods by which the criteria for system operation described in Section 7. 2 were included in the computer program, can be visualized from an examination of Plate 13 which gives simplified flow charts for all major

sections of the program. Important phases of the computation for a system which includes the Mactaquac development with six units installed, but which does not include a storage and power development at the Rankin Rapids site, are illustrated graphically on Plate 14.

The basic flow diagram on Plate 13 shows the interrelation of the various subsections of the program. Apart from input and output, the sub-

sections can be divided into two groups, the first dealing with the rule curve

calculations for the primary storage and the second dealing with the system

simulation. Computation of the rule curve involves twelve groups of calculations, one for each month of the artificial low flow year. The system simulation involves 240 groups of calculations, one for each month of the 20-year period of power and energy computations. A complete run involves calculation of the rule curve for the primary storage, follo-wed by the system simulation in which a fixed ann.tia1 load demand is met during each year of .the 20-year period to find the average amount of thermal energy generation required.

Average, minimum, and maximum values of important functions as described

in Section 7.4 are obtained as output. - 108 -

Both the rule curve computation and the system simulation have, as a first step, the calculation of a residual load curve which must be met by hydro-electric plants on the Saint John River and by thermal plants. A simplified flow chart for the residual load curve computation (subsection RL) is given on Plate 13, and Blocks RL2, RL5, and RL6 are illustrated on Plate 14.

In Block RL2 the load duration curves for the systems under consideration are added to give a combined load duration curve, The illustration is for the month of March, with peak demands of 563 megawatts in New Brunswick and 382 megawatts for the incremental demand in Nova Scotia. It is estimated that these loads will be experienced around the year 1973. Outputs from the

Passamaquoddy Tidal Power Project and the Musquash and Milltown developments, all of which are not subject to storage control, are subtracted from the combined load curve in Blocks RL4, RL5, and RL6, respectively, The illustration shows subtraction of the outputs of the Milltown and Musquash developments.

The rule curve computation (subsection Re) is made for each month of the artificial year to find the minhum amouIlt: of storage which must be available at any given time to utilize the capacity of hydro plants on the Saint

John River on'the peak of the residual load curve. In determining this rule curve, it is assumed that all reservoirs will be empty at March 31 of the artificial year , and calculations are worked backwards from this point in twelve monthly intervals to the beginning of the artificial year. If, at any point in this calculation, it is found that the minimum storage requirement is greater than that which is available, the load demand is automatically reduced by steps to the value which can just be met This load is then the low flow dependability of the system being considered, and is the load demand which is applied in the system simulation.

The rule curve computation for a single month is illustrated graphically on Plate 14. The first graph (Bl.ock SSP) shows the base load output from the thermal stations wbtracted at the bottom of the residual load curve, the remaining or peak portion of the curve being met by hydro-electric developments on the Saint John and Tobique Rivers with a minimum of energy generation and hence a minimum withdrawal from the primary storage. The illustration is for the month of March and the amount of water withdrawn from the primary storage during that mocth is plotted i~ Block RC6 to give r?~epair-t on the rule curve. By repeating the process for the month of February, a second point is obtained, the process being continued month by month to obtain the complete rule curve. The dotted line on the illastration of Block RC6 shows an unsuccessful attempt to obtain a rule curve, The annual firm peak demand was too great and had to be reduced until the top of the rule curve came below the line representing the maximum live storage volu-me in the reservoir.

A simplified flow chart of the system simulation is shown on

Plate 13 under subsection SS. Alternative paths in this subsection are further detailed in subsections SSB and SSP, referring, respectively, to conditions of hydro base and hydro peak loading. The choice of the path taken in subsection

SS is determined by Block SS2 in which storage remaining in the primary reservoir following peak load operation of hydro plants, as illustrated on to the value which can just be met This load is then the low flow dependability

of the system being considered, and is the load demand which is applied in the

system s imulation.

The rule curve computatioc for a single month is illustrated graph-

ically on Plate 14. The first graph (Block SSP) shows the base load output

from the thermal stations subtracted at the bottom of the residual load curve, the remaining or peak portion of the curve being met by hydro-electric developments on the Saint John and Tobique Rivers with a minimum of energy genera-

tion and hence a minimum withdrawal from the primary storage. The illustra-

tion is for the month of March and the amount of water withdrawn from the

primary storage during that month is plotted in Block RC6 to give one point on

the rule curve. By repeating the process for the month of February, a second

point is obtained, the process being continued month by month to obtain the

complete rule curve. The dotted line on the illustration of Block R66 shows

an unsuccessful attempt to obtain a rule curve. The annual firm peak demand

was too great and had to be reduced until the top of the rule curve came below

the line representing the maximum live storage volume in the reservoir.

A simplified flow chart of the system simulation is shown on

Plate 13 under subsection SS. Alternative paths in this subsectiorz are further

detailed in subsections SSB and SSP, referring, respectively, to conditions of

hydro base and hydro peak loading. The choice of the path takeE in subsection

SS is determined by Block SS2 in which storage remaining in the primary

reservoir following peak load operation of hydro plants, as illustrated on - 111 -

cost was equal to that which would be experienced at the level of monthly peak power demand. Both conditions are illustrated on Plate 14. By adopting these assumptions, the incremental thermal energy costs obtained were slightly greater than would actually be experienced. - 112 -

8 - SEQUENCES OF DEVELOPMENT

The manner in which the Saint John River Board interpreted those parts of the Terms of Reference related to power generation is described in

Section 1.2. The approach which has been adopted involves a detailed study of a number of possible sequences of power development in New Brunswick, and a comparison of these sequences to find the effects, in terms of both energy and money, of developing upstream storage on the Saint John River.

The sequences of development which were studied in detail, and which are described in this section, are:

Case I

A sequence of development in New Brunswick without Rankin Rapids storage, in which the transmission interconnection between New Brunswick and Nova Scotia is use'd only for the sharing of spare capacity and spinning reserve.

Case I1

A sequence of development in New Brunswick without Rankin Rapids storage, in which the transmission interconnection between New Brunswick and Nova Scotia is used for the sharing of spare capacity and spinning reserve, and for the transfer of energy to give the rnaxt-muzk economy in power generation in both provinces.

Case I11

Sequences in which the Rankin Rapids storage and power development is brought into operation in 1968 'at 200 megawatts. The alternatives which were studied are as follows:

(a) - A sequence of development in New Brunswick identical with that in Case 11; the Rankin Rapids storage and power development is operated to meet a load in Maine. - 113 -

A modification of the sequence of development of Case 11, to give improved economy in New Brunswick; the Rankin Rapids storage and power development is operated to meet a load in Maine.

A sequence of development in New Brunswick identical with that in Case III(b), but with the Rankin Rapids storage and power development operated integrally with generation in New Brunswick and Nova Scotia to meet the combined New Brunswick-Nova Scotia loads and a load in Maine.

Sequences in which the Rankin Rapids storage and power development is brought into operation in 1968 at 200 megawatts, increasing to 460 megawatts in 1970 coincident with the commissioning of the Passamaquoddy Tidal Power Project.

(a) - A sequence of development in New Brunswick identical with that in Case 11; the Rankin Rapids storage and power development is operated in conjunction with the Passamaquoddy Tidal Power Project to meet a load in Maine.

(b) - A modification of the sequence of development of Case Ii, to give improved economy in New Brunswick; the Rankin Rapids storage and power development is operated in conjunction with the Passamaquoddy Tidal Power Project to meet a load in Maine.

(c) - A sequence of development in New Brunswick identical with that in Case IV(b), but with the Rankin Rapids storage and power development and the Passamaquoddy Tidal Power Project operated integrally with generation in New Brunswick and Nova Scotia to meet the combined New Brunswick-Nova Scotia loads and a load in Maine. - 114 -

In estimating the economic sequence of power development for a mixed hydro-thermal system, account must be taken of several variables, the more important of which are the interest rate on borrowed money and .the cost of fuel. The rates of interest which electric utilities will have to pay for money borrowed in the future are unknown, and the future costs of fuel in New

Brunswick are uncertain €or a variety of reasons.

When faced with a problem of this type, an approach which is often useful is to choose upper and lower limits for major variables, and to make several economic comparisons using alternative combinations of these .Timiting values to find the maximum variation which may be possible in power costs,

This approach has been adopted in part in the studies of possible sequences of power development in New Brunswick in that a high interest rate has been used, and the results are such that use of an arbitrary lower limit would merely emphasize the trends which are evident from the study.

The approximate yield to maturity for provincial bonds issued by

New Brunswick over the past 12 years for construction .of power system facilities has varied from a minimum of approximately 3.5 per cent in 1948 to a maximum of 5.5 per cent in 1960.

Using an interest rate of 5.5 per cent, it was established that potential hydro-electric development on the Saint John River will be economic when compared with thermal generation. The effects of lower interest rates, although not examined in detail, would be to further enhance .the comparative value of hydro- electric developments. - 115 -

Uncertainties about the future costs of fuel for thermal-electric

stations arise for several reasons. The cost of Bunker C oil as recorded by

Platt' s oilgram, has fluctuated considerably in the past although ehibiting a

long term trend towards higher cost. If Bunker C oil were the only fuel

available in New Brunswick, it would be reasonable to assume in economic

studies that the cost of incremental thermal energy generation will increase

in the future.

However, two recent developments in New Brunswick may tem- porarily reverse this trend. An oil refinery has recently been built in Saint

John, adjacent to the site of the new East Saint John thermal plant, and re-

finery pitch can be delivered direct to the thermal plant at costs which may

be less than 30 cents per million Btu. Another development involves mechan-

ization of mining operations at the Minto coalfield with a possible reduction

in the cost of coal at thermal plants in the province.

The Board assumed a constant future fuel cost in the sequence

studies, equal to the cost of Bunker C oil as of January 1959, n~z-sly,35

cents per million Btu at the burners. This figure may be compared with the

following typical costs for fuels at the burner in June 1960.

Coal e a a 49 cents per million B~U

Bunker C oil a e 30 ceqts per million Btu

..Variationin load growth is another factor which can have a bearing

on the economic sequence of power development in New Brunswick. Load

growth on the system of The New Brunswick Electric Power Commission is - 116 -

discussed in Section 3.2 of this report, and it is concluded that future growth in firm demand at the rates experienced over the last 10 years can be anticipated. The rate used in all sequence studies was 9.4 per cent per year and it is expected that minor changes in this rate would not change the order in which potential generating facilities should be developed to give maximum overall economy.

Based on the foregoing assumptions, the economic sequence of future power development in New Brunswick was determined for any given set of conditions by comparing total system costs resulting from the addition of alternative generating facilities, at each stage of system expansion. Total system costs were measured at the points of distribution in New Brunswick and transmission liabilities associated with alternative generating facilities were, therefore, taken into account. The total system costs which were compared were those which would be experienced when the power output from each of the alternative power sources is fully utilized in meeting the load demand, assuming a 15 per cent spare capacity requirement on.the system.

There are a number of assumptions inherent in this method of determining the economic sequence of power development for any given set of system conditions. It is assumed that any power development which is found to be economic at one stage in the sequence will continue to be economic throughout its useful life, Broadly speaking, this is true for hydro-electric plants on the Saint John River but may not be true for thermal plants. - 117 -

On the other hand, it is assumed that the requisite amounts of

capital can be borrowed on an equal basis for the construction of thermal or

hydro developments, the latter generally involving higher initial capital ex-

penditures. This assumption and the fact that present worth comparisons

were not made, give results which may favour hydro-electric developments,

' and work in a direction opposite to that of the assumption in the preceding

paragraph.

It is believed, therefore, that the methods adopted in the sequence

studies, although approximate in certain areas, are nevertheless adequate in

answering the questions posed by the Terms of Reference. More positive

answers will be obtained only when it is possible to estimate with greater

accuracytheprobable future trends in fuel costs ai thermal stations, at which

time it maybe desirable to repeat the studies for a range of possible interest

rates and to introduce present worth comparisons.

8.1 - Case ISequence

Details of the economic sequence established for Case I using

the methods described above, are given on Plate 15, the governing system

conditions being as follows:

(i) - There are no further interconnections between electric utilities in New Brunswick and Maine.

(ii) - The PassamaqEoddy Tidal Power Project and the Rankin Rapids development are not built.

(iii) - The transmission interconnection between New Brunswick and Nova Scotia is used only for the sharing of spare capacity and spinning reserve - 118 -

(iv) - A minimum of 15 per cent spare capacity is maintained on the combined systems of New Brunswick and Nova Scotia.

(v) - The net capability of the Nova Scotia utility systems is never less than the peak firm power demand on those systems.

(vi) - The net capability and flood dependability of The New Brunswick Electric Power Commission system is never less than the peak firm power demand on that system.

(vii) - The system of The New Brunswick Electric Power Commission is operated in accordance with the criteria described in Section 7. 2 of this report.

The schematic index given on Plate 16, defines the 84 computer

runs which were made, and shows the various stages of system expansion which were studied in detail in determining the economic sequence of power

development in New Brunswick under the governing conditions listed above.

Starting with the existing system, the first unit at the East Saint

John thermal plant, now under construction, and the planned third unit at the

Beechwood development were added. At this point, the value of developing

varying amounts of storage at potential sites on tributaries of the Saint John

River was tested and in all cases it was found that with the limited head at

present developed on the Saint John River, an increase in the unit system

co sts would result

With .the assumed rate of load growth, additional c’apacity is

needed in New Brunswick by the year 1963. Of the four alternative power sources which were examined at this stage, it was found that a second unit at the East Saint John thermal plant will be the most economic. New hydro- electric developments or extensions to existing developments on the Saint

John River could not yet be utilized on the peak of the load curve, even when potentially economic storages on .the tributaries were added.

Similar conditions applied to the next stage of system expansion in 1966, and a third unit on the East Saint John thermal plant was added. It should be noted that the comparisons at this stage made it possible to eliminate

Hawkshaw in favour of the Mactaquac development and provided approximate cost indices for future comparisons. By the year 1968, the system load had increased to the point where the output from three units of the Mactaquac development could be utilized on the peak of the load curve, even under conditions of low river flow, giving sufficient firm power and energy output to make the initial installation more economic than an alternative thermal power kource.

Once the initial installation at a hydro-electric development on the

\, Saint John River can be justified, extra units can be added to provide peaking capacity at fairly low cost, the system energy requirement being met by increasing the output of existing thermal plants or by building new ones. This was proved to be the most economic procedure for the remainder of Case I sequence up to the year 1980.

Inclusion of the Mactaquac development increased the total head developed on the Saint John River, and in 1972 it was found that the storages at Lac Squatec and at Glazier Lake were economic primarily because of the - 120 -

increase in hydro-electric energy generation, but also on account of the short

term capacity benefit obtained.

The extent to which hydro-electric developments on the Saint John

River were included in Case I sequence, was limited only by the period of

study and by the need to develop thermal power for base load energy genera-

tion. Ifthe studies had been carried slightly beyond 1980, the extension of the

Grand Falls development would have been found to be economic.

In summary, it can be said that the Mactaquac development and the ex-

tension to the Grand Falls development are economic if developed in conjunction with thermal power, evenwithout energy inter change withNova Scotia andwith-

out storage at the RankinRapids development. Storage at Lac Squatec and at

Glazier Lake willbe of value in this sequence, when the Mactaquac site is developed.

Once the economic sequence under the governing conditions of

Case I had been established, a series.of computer runs was made to deter-

mine system costs and the power and energy outputs of each development,

yearby year, over the 20-year periodto 1980. The results of these runs are

given in Table 52 and on Plate 15, the outputs and costs for hydro-electric

and thermal-electric plants on the system being grouped in both cases.

The value of the Mactaquac development is illustrated by the

figures in Table 53, where a comparison is madewiththe cost of generating

equivalent amounts of power and energy, using costs associated with 150-

megawatt thermal units. With six units at the Mactaquac development, 81 3

per cent of the total energy potential of the site can be utilized in meeting

the firm demand in the year 1980, without storage at Rankin Rapids. TABLE 52

CASE I - AVERAGE ANNUAL ENERGY GENERATION AND COSTS IN NEW BRUNSWICK

Annual Generation Unit Energy Million Kwh. Annual Costs - Million Dollars Cost-/1 -Year Hvdso Thermal Total Hvdso Thermal Subtotal Transmission Total Mills /Kwh 1960 934.1 259. 0 1193. 1 4. 78 3.86 8. 64 3. 15 11.79 10.29 1 952.9 345.9 1298.8 4. 78 4.71 9.49 3. 27 12.76 10.24 2 1030.8 384.2 1415. 0 5.10 4. 89 9.99 4. 00 13.99 LO. 31 3 1046.0 490.4 1536.4 5.10 5.72 10.82 4. 00 14.83 10. 05 4 1057. 7 615.9 1673. 6 5.10 6. 16 11.26 4,OO 15.26 9.50 5 1066.7 749.5 1816.2 5.10 6. 64 11.74 4. 00 15.75 9. 03 6 1074.0 895.3 1969. 3 5.10 7.87 12.97 4.43 17.39 9.20 I 7 10’99.8 1063.6 2143.5 5.10 8.42 13.52 4. 43 17.95 8.72 P 8 1869. 1 453.5 2322.6 10.95 6.45 17.40 4. 50 21.90 9.82 N P 1937.5 596,7 2534.2 10.95 6.92 17.87 4. 50 22.37 9 9.19 I 1970 1982.7 762.7 2745.4 10.95 7.48 18.43 4. 50 22.93 8.70 1 2016.7 966.3 2983.0 10.95 8. 19 19.14 4.50 23.64 8. 25 2 2253.9 987.8 3241.7 12.22 8.26 20.48 4. 50 24.98 8. 03 3 2290.7 1230.8 3521.5 12.22 10.51 22.73 4. 94 27.67 8. 19 4 2315.4 1507. 1 3822.5 12.22 11.40 23.62 4. 94 28.56 7.78 5 2332.5 1827.8 4160. 3 12.22 12.45 24.67 4.94 29.61 7.41 6 2350.7 2163.4 4514.1 12.22 15.07 27.29 4.94 32.23 7.44 7 2498.7 2411.4 4910. 1 13.54 15.87 29.41 5. 38 34.79 7. 38 8 2514.6 281’9.8 5332.4 13.54 18.76 32.30 5*58 37.88 7.40 9 2524.9 3256.3 5781.2 13.54 20.14 33.68 5. 58 39.26 7. 07 1980 2534.8 3747.9 6282.7 13.54 23.32 36.86 5.58 42.44 7. 04

-/1 In computing unit energy costs, annual generation has been reduced by 4 per cent, to take account of transmi s s ion los s e s - 122 -

TABLE 53

COMPARISON BETWEEN COSTS OF HYDRO-ELECTRIC GENERATION ON THE SAINT JOHN RIVER AND THE COSTS OF EQUIVALENT THERMAL GENERATION

CASE I SEQUENCE - YEAR 1980

Mactaquac Item Unit Development

Number of units - 6

Net capability Mw 320

Annual average energy available from total river flow at site Million kwh 1,.681

Annual average firm energy generation Million kwh 1,367

Utilization of available energy Per cent - 81.3

Capacity factor Per cent . 48.8

Estimated capital cost Million dollars 109. 1

Total annual charges Million dollars 7.732

Average cost of energy and associated capacity at site Mills / kwh 5. 66

Cost of equivalent thermal energy and capacity at site Mills / kwh 6. 20 - 123 -

.8.2 - Case I1 Seauence

Details of the economic sequence established for Case I1 are given on Plate 17, the governing system conditions being as follows:

(i) - There are EO further interconnections between electric utilities in New Brunswick and Maine.

(ii) - The Passarnaquoddy Tidal Power Project and the Rankin Rapids development are not built.

(iii) - The transmission interconnection between New Brunswick and Nova Scotia is used for the sharing of spare capacity and spinning reserve and for the interchange of energy to give the maximum of economy in operation.

(iv) - A minimum of 15 per cent spare capacity is maintained on the combined systems of New Brunswick and Nova Scotia.

(v) - The net capability of the Nova Scotia utility systems is never less than the peak firm power demand on those systems.

(vi) - The net capability and flood dependability of The New Brunswick Electric Power Commission system is never less than the peak firm power demand on that system.

(vii) - The combined systems of The New Brunswick Electric Power Comrnis sion and incremental load and generation of the Nova Scotia utilities are operated in accordance with the criteria described in Section 7.2 of this report.

As stated in Section 4, complete basic information for existing generation and planned additions of the Nova Scotia utilities was not available to the Board in time for the system studies. From the information which was available, it was estimated that the net capability of existing and planned - 124 -

generation of these utilities will amount to 365 megawatts in the year 1963.

The load demand which can be met while maintaining reserve capacity equal to 15 per cent of the peak demand, will then be 318 megawatts. For the purposes of the studies, it was assumed that any generation and load in excess of these amounts could be integrated with the system of The New Brunswick

Electric Power Commission, the combined system being operated for maximum economy.

The possibility of energy interchange between the utilities of New

Brunswick and Nova Scotia was studied primarily to determine the extent to which development of the remaining power potential of the Saint John River in New Brunswickmay be accelerated. It was assumed that future generation in Nova Scotiawillbe thermal, and that generation costs will be equal to those anticipated for new thermal plants in New Brunswick. However, if thermal power costs in Nova Scotia were higher, the tendency would be to accelerate the development of power on the Saint JohnRiver inNew BrunswickinCase I1

sequence; on the other hand, the construction of ahydro- electric development at Wreck Cove in Nova Scotia may delay construction of these developments.

Another point of note is that incremental generation requirements in Nova Scotia are practically identical in all of the sequences which were

considered and, for this reason, itwas unnecessary to include transmission costs in Nova Scotia as they are common to all sequences.

A total of 73 computer runs was made in determining the economic

sequence under the governing conditions for Case I1 as detailed on the schematic - 125 -

index shown on Plate 18. The economic sequence for Case 11 is similar to that for Case I, except that the construction of additional generation on the

Saint John River is accelerated because of the high potential energy generation available at thermal plants in Nova Scotia during periods of low flow on the Saint John River.

A second unit at the East Saint John thermal plant was again found to be economic, following commissioning of the first unit at that plant and the planned third unit at the Beechwood development. After this, the load growth in New Brunswick for the next 10 years can be most economically met by the

Mactaquac development, with a total net capability of 414 megawatts in eight fmits, and by a single thermal unit of 150-megawatt capacity installed in 1973.

It is then economic to extend the existing Grand Falls to a total net capability of 289. 0 megawatts, while at the same time installing an additional 150- megawatt thermal unit

In sumrnary, it can be said that development of the power potential of the Saint John River in New Brunswick can be accelerated if energy is interchanged between the systems of The New Brunswick Electric Power

Commission and the Nova Scotia utilities to give a maximum economy in operation. Storage at Lac Squatec, although economic for its energy con- tribution, would not accelerate the development of the river in this sequence, and was not included.

Once the economic sequences under the governing conditions of

Case II had been established, a series of computer runs was made to determine - 12s -

system costs and the power and energy outputs of each .development, year by year, over a 20-year period to 1980. The results of these runs are given in

Table 54, and on Plate 17, the outputs and costs for hydro-electric and thermal,- electric plants on the system being grouped in both cases. The cost figures given in Table 54 are for comparison purposes only, as they do not include costs associated with the existing systems in Nova Scotia and future transmission requirements in Nova Scotia.

In Table 55, the cost of power and energy generationat the Mactaquac development and at the extension of the Grand Falls development, are compared with the cost of generating equivalent amounts of power and energy at a thermal plant, using costs associated with 150-megawatt units. The

Mactaquac development and the Grand Falls extension operate at substantially different capacity factors and the unit costs are not subject to comparison with each other. Since eight units were installed in the Mactacquac development by 1980 in Case I1 sequence, the percentage utilization of the total energy potential of the site increases to 88. 0 per cent. This figure compares with the 81. 3 per cent utilization obtained in Case I sequence with six units installed.

8.3 - Case I11 Sequences

Three sequences were studied in Case 111, the purpose being to provide information which. is essential to a complete understanding of the effects of upstream storage on power generation on the Saint John River in New I

TABLE 54

CASE I1 - AVERAGE ANNUAL ENERGY GENERATION AND CQSTS IN NEW BRUNSWICK AND NOVA SCOTIA

Annual Generation Unit Energy Million Kwh. Annual Costs - Million Dollars Cost-/3 Year Hydro Thermal Total Hydro Thermal!! Subtotal Transmission!? Total MillslKwh 1960 934.1 259.0 1193. 1 4. 78 3.86 8. 64 3. 15 11.79 10.29 1 952.9 345.9 1298.8 4. 78 4.71 9.49 3. 27 12.76 10.24 2 1030.8 384.2 1415.0 5.10 4.89 9.99 4. 00 13.99 10.31 3 1046.0 534.0 1580.0 5.10 6.59 11.69 4-00 15.69 10.34 4 1057.7 809.9 1867. 6 5.10 8. 01 13.11 4.00 17.11 9.54 5 1080. 3 1085.4 2165.7 5.10 8.83 13.93 4.00 17.93 8. 63 6.1796.2 692.4 '2488.6 10.44 8.76 19.20 4. 67 23.87 9.99 7 1832.2 1020.0 2852.2 10.44 9.82 20.26 4. 67 24.93 9.10 I r 8 1854.8 1380.8 3235.6 10.44 12.53 22.97 4. 67 27.64 8. 90 N 4 9. 2069.5 1605.5 3675.0 10.97 13.25 24.22 4. 67 28.89 8. 19 I 1970 2211.8 1917.1 4128.9 11.56 14.25 25.81 4. 67 30.48 7. 69 1 2310.6 2322.9 4633.5 12.22 17. 13 29.35 4.71 34.06 7. 66 2 2389.2 2794.3 5183.5 12.78 18.63 31.41 4.71 36.12 7. 26 3 2406.5 3382.0 5788.5 12.78 22.09 34.87 4. 71 39.58 7.12 4 2419.7 4019.3 6439. 0 12.78 25.73 38.51 4. 71 43.22 6.99 5 2543.8 4616.6 7160.4 14.06 29.25 43.31 4.94 48.25 7. 02 6 2880.5 5060.9 7941.4 16.72 30.65 47.37 5.07 52.44 6. 88 7 2899.6 5894.0 8793.6 16.72 34.90 51.62 5.07 56.70 6. 7'2 8 2914.3 6796.7 9711.0 16.72 41. 05 57.77 5.44 63.21 6. 78 9 2925.0 7783.3 10708b 3 16.72 45.79 62.51 5.44 67.95 6. 61 1980 3005.4 8786.9 11792.3 17.80 48.90 66.70 5.44 72.14 6. 36

!1 - Thermal costs in Nova Scotia have been computed using anticipated New Brunswick costs. !? - The cost of transmission in Nova Scotia is not included. -13 - In computing unit energy costs, annual generation has been reduced by 4 per cent, to take account of transmission losses. - 128 -

TABLE 55

COMPARISON BETWEEN COSTS OF HYDRO-ELECTRIC GENERATION ON THE SAINT JOHN RIVER AND THE COSTS OF EQUIVALENT THERMAL GENERATION

CASE I1 SEQUENCE - YEAR 1980

DeveloDment Grand Falls Item Unit Mactaquac Extension

Number of units 8 6

Net capability Mw 41 4 289 f

Annual average energy available from total river flow at site Million kwh 1, 670 1, 018::

Total annual average firm energy generation Million kwh 1,470 867 f

Utilization of available energy Per cent ' 88.0 8 5 . 2 ::<

Capacity factor Per cent 40. 6 34.2%

Estimated capital cost Million dollars 123.6 49.8

Total annual charges Million dollars 8.955 3.740

Average cost of energy and associated capacity at site Mills/kwh 6.10 9. 63

Cost of equivalent thermal energy and capacity at site Mills/ kwh 6.80 10.90

9' 9' These figures apply to the total installation at the Grand Falls plant. Energy generated by the extension can be estimated approximately by subtracting the average annual energy generated at the existing Grand Falls development in Case I for the year 1980, ,namely, 478 million kilowatthours from the total annual average firm energy generation. The net capability of the six-unit extension is 229 megawatts. - 129 -

Brunswick. These sequences fall naturally into two groups depending on the methods adopted for the control of storage at the Rankin Rapids development.

In Cases III(a) and III(b1, it was assumed that the Rankin Rapids development will form part of a utility system in Maine which is not interconnected with the systems of New Brunswick and Nova Scotia, and that the storage will be controlled for maximum. at-site energy generation. In Case

III(c) it was assumed that interconnection will be established at 230 kv between

New Brunswick and the utility in Maine, and that the Rankin Rapids storage will be controlled to give maximum benefit to the interconnected utilities.

For Cases III(a) and III(b) in which there is no further transmission interconnection between New Brunswick and Maine, it was necessary, first of all, to find a method whereby the Rankin Rapids storage can be controlled for maximum at- site energy generation. The proposed live storage volurne of 2, 800, 000 acre-feet will allow a high utilization of runoff at the

Rankin Rapids site. However, even greater utilization and, hence, greater energy output, can be obtained if the development is operated integrally with a thermal plant. A series of computer runs was therefore made to find the optimum amount of thermal power which, when operated integrally with the

Rankin Rapids development, will result in maximum at- site firm energy generation. In all cases, the load demand had the same characteristics as the present utility load in Maine as defined on Plate 19 and Table 56, and the peak demand being chosen so that 15 per cent spare capacity was available - 130 -

TABLE 56

ASSUMED MONTHLY DEMAND FACTORS FOR A UTILITY LOAD IN MAINE

Monthly Demand Month Factors

January ..O.Dm.Oe.Oe..e. 941

February ., e e 903 March...... ,...... 888

April. Do e De 875

May. a eo a ooloa OO. 878

June OoO~OOeDOO.OOOoOO.O 880 July. ., e *. ., . *. . .914

August ,, D. e 0 939

September a e 905

October. Do. Do -.e 930

November Do D. 962

December e D. ., 1.000

On Plate 20, the values of potential average at-site energy and firm energy output from the Rankin Rapids development are plotted against the rated capacity of the thermal plant. It can be seen from this graph that if the Rankin Rapids development is operated as an isolated hydro-electric development; 87.5 per cent of the available energy at the site can be utilized.

However, when the development is operated integrally with a thermal plant of between 100- and 150-megawatt capacity, the average annual at-site firm energy generation increases to a maximum of approximately 1, 250 million kilowatthours, or 99.5 per cent of the available energy. The total capacity of existing thermal plants of utilities in Maine is approximately 400 megawatts, - 131 -

and there would therefore appear to be no difficulty in operating the Rankin

Rapids development in the manner described above.

Actual values of mean monthly outflow from the Rankin Rapids development for the 20-year period of the computations were obtained for the

studies of Cases III(a) aEd Il[l(b), assuming that the Rankin Rapids development will have a capacity of 200 megawatts and will be operated integrally with 150 megawatts of thermal generation in Maine.

Case III(a) Sequence - The sequence of development adopted for Case

III(a) is identical with that for Case I1 and is shown on Plate 21. Governing

system conditions are as follows:

(i)- There are no further interconnections between electric utilities in New Brunswick and Maine.

(ii) - The Passamaquoddy Tidal Power Project is not built.

(iii) - A storage and power development at the Rankin Rapids site is commissioned in 1968 with a total installation of 200 megawatts, and is operated in conjunction with a 150-megawatt thermal io- stallation in Maine to meet a load demand ?in Maine

(iv) - The transmission interconnection between New Brunswick and Nova Scotia is used for the sharing of spare capacity and spinning reserve and for the interchange of energy to give the maximurn of economy in operation.

(VI - A minimum of 15 per cent spare capacity is maintained on the combined systems of New Brunswick and Nova Scotia.

(vi) - The net capability of the Nova Scotia utility systems is never less than the peak firm power demand on those systems. - 132 -

(vii) - The minimum capability and flood dependability of The New Brunswick Electric Power Commission system is never less than,the peak firm power demand on that system.

(viii) - The combined systems of The New Brunswick Electric Power Commission and incremental load and generation of the Nova Scotia utilities are operated in accordance with the criteria de-. scribed in Section 7. 2 of this report.

Of the governing conditions listed above, conditions (iv) to (viii) inclusive are identical with those adopted for Case I1 sequence, and all of the qualifications associated with Case I1 sequence are applicable,

Since the sequences for Cases II and III(a) are identical, the only computer work required was the determination of system costs and the power and energy outputs of each development, year by year, over a 20-year period to 1980, using Rankin Rapids outflow obtained by the method previously described. The results of these runs are given in Table 57 and on Plate 21, the outputs and costs for hydro-electric and thermal plants on the system being grouped in both cases. The figures given in Table 57 are for comparison purposes only, as they do not include costs associated with the existing systems in Nova Scotia and future transmission requirements in Nova Scotia.

The effects of storage at the Rankin Rapids development are clearly illustrated by the figures given ia Table 58, which show further increases in the percentage utilization of the total energy potential of power sites on the Saint John River in New Brunswick, and consequent reductions in unit costs, TABLE 57

CASE III(a) - AVERAGE ANNUAL ENERGY GENERATION AND COSTS IN NEW BRUNSWICK AND NOVA SCOTIA

Annual Generation Unit Energy Million Kwh Annual Costs Million Dollars - Cost,/4 Year HydroE Thermal Total Hydro Thermal!! Subtotal Transmissionk Total Mills/Kwh 1960 934.1 259.0 1193. 1 4. 78 3.86 8. 64 3. 15 11.79 10.29 1 952.9 345.9 1298.8 4. 78 4.71 9.49 3. 27 12.76 10. 24 2 1030.8 384.2 1415.0 5,lO 4.89 9.99 4.00 13.99 10.31 3 1046.0 534.0 1580. 0 5.10 6.59 11.69 4.00 15.69 10.34 4 1057.7 809.9 1867.6 5.10 8. 01 13.11 4.00 17.11 9.54 5 1080.3 1085.4 2165.7 5.10 8.83 13.93 4.00 17.93 8. 63 6 1796.2 692.4 2488.6 10.44 8.76 19.20 4. 67 23.87 9.99 7 1832.2 1020.0 2852,. 2 10.44 9.82 20.26 4. 67 24.93 9.10 8 2081.3 1154.3 3235.6 10.44 11.81 22.25 4. 67 26-92 8. 67 I w 9 2338.3 1336.7 3675.0 10.97 12, 39 23.36 4. 67 28.03 7.95 w w 1970 2505.0 1623.9 4128.9 11.56 13.30 24.86 4. 67 29.53 7.45 I 1 2613.3 2020.2 4633.5 12.22 16.17 28.39 4.71 33.10 7.44 2 2692.8 2490.7 5183.5 12.78 17.66 30.44 4. 71 35.15 7. 06 3 2710. 1 3078.4 5788.5 12.78 21.14 33.92 4.71 38.63 6.95 4 2723. 0 3716.0 6439.0 12.78 24.78 37.56 4. 71 42.27 6, 84 5 2834.0 4326.4 7160.4 14.06 28.35 42.41 4.93 47.34 6. 89 6 3275.5 4665.9 7941.4 16.72 29.41 46.13 5.07 51,20 6. 72 7 3291.2 5502.4 8793.6 16.72 33.68 50.40 5.07 55.47 6.57 8 3303.0 6408.0 9711.0 16.72 39.84 56.56 5.44 62.00 6. 65 9 3311.6 7396.7 10708.3 16.72 44.59 61.31 5.44 66.75 L49, 1980 3358.8 8433.5 11792.3 17.80 47.80 65.60 5.44 71.04 6. 28 !! - Thermal costs in Nova Scotia have deen computed using anticipated New Brunsw-zk costs. -12 - The cost of transmission in Nova Scotia is not included. -13 - The effects of flow regulation at Rankin Rapids from 1968 onwards are included at no cost. 5 - In computing unit energy costs, annual generation has been reduced by 4 per cent, to take account of tr ansmis s ion los s e s . - 134 -

TABLE 58

COMPARISON BETWEEN COSTS OF HYDRO-ELECTRIC GENERATION ON THE SAINT JOHN RIVER AND THE COSTS OF EQUIVALENT THERMAL GENERATION

CASE Ill(a) SEQUENCE - YEAR 1980

D eveloDment Grand Falls Item Unit Mactaquac Extension

Number of units - 8 6

Net capability Mw 41 4 289 *

Annual average energy available from total river flow at site Million kwh 1,707 1,014*

Total annual average firm energy generation Million kwh 1, 612 984s

Utilization of available energy Per cent 94.5 97.0::

Capacity factor Per cent 44.5 38,7*

Estimated capital cost Million dollar s 123.6 49.8

Total annual charges Million dollars 8.955 3,740

Average cost of energy and associated capacity at site Mills / kwh 5.56 7.40 Cost of equivalent thermal energy and capacity at site Mills/kwh 6. 50 9. 06

% These figures apply to the total installation at the Grand Falls plant. Energy generated by the extension can be estimated approximately by subtracting the average annual energy generated at the existing Grand Falls development in Case I for the year 1980, namely, 478 million kilowatthour s from the total annual average firm energy generation. The net capability of the six-unit extension is 229 megawatts. - 135 -

Case III(b) Sequence - Case III(b) sequence is a modification of Case

III(a) to take full advantage of the regulation provided by the Rankin Rapids reservoir. The modified sequence is shown on Plate 22, the governing conditions being identical with those for Case III(a). In all, 34 computer runs . were made in determining the economic sequence in Case III(b) as detailed on the schematic index shown on Plate 23. .The sequence of development up to and including .the year 1963 is unchanged, as additional generation on the

Saint John River cannot be commissioned before that date. It was then assumed that if the Rankin Rapids storage and power development is to be commissioned in 1968, the necessary decision would be made prior to 1963, in which case either .the Mactaquac development or an extension to the Grand Falls development could be constructed and commissioned by 1966, in anticipation of the availability of storage at the Rankin Rapids development for control of river flow.

On this basis, comparisons were made as detailed on Plate 23, and it was found that the installation of three units in an extension of the

Grand Falls development, followed by construction of the Mactaquac development up to a total installation of eight units, gave slightly lower power costs than other alternatives., Thereafter, the Grand Falls development can be further extended and the Morrill development constructed, at which point the entire potential of the Saint John River in New Brunswick above tidehead will have been developed. - 136 -

The results of annual computer runs for the 20-year period.to

1980 for Case III(b) sequence are given in Table 59, and on Plate 22. A comparison with equivalent thermal generation is given in Table 60, from which it can be seen that generation costs for the Morrill development are slightly greater than the cost of generating equivalent amounts of energy and capacity at a thermal plant. Inclusion of the Morrill development at this stage of the sequence is, therefore, in question. However, the economic limit of installed capacity at the Morrill development was not studied, and it is anticipated that additional capacity could be installed, bringing generation costs down to below the equivalent costs for thermal power. The figures of percentage utilization of available energy at the Mactaquac and Grand Falls sites are almost identical with those for Case III(a) and represent an upper limit of utilization which can be economically obtained without transmis sion interconnection between the utilities in New Brunswick and Maine.

In summary, if it is known in advance that the Rankin Rapids

storage and power development will be commissioned by the year 1968, the

sequence of power development downstream will change from that of Case

III(a), and it will be economic to extend the Grand Falls development, to develop the Mactaquac site, and probably to develop the Morrill site to their full power potelltials over a 15-year period starting in 1963, A-dditior-a1

storage on tributaries of the Saint John River, if not already developed by

1968, would then be of little value. TABLE 59

CASE III(b) - AVERAGE ANNUAL ENERGY GENERATION AND COSTS IN NEW BRUNSWICK AND NOVA SCOTIA

Annual Generation Unit Energy Million Kwh Annual Costs Million Dollars - Cos& Year Hydro!? Thermal Total Hydro Thermalk Subtotal Transmission-L Total Mills/Kwh

1960 934.1 259.0 1193. 1 4.78 3.86 8. 64 3. 15 11.79 10.29 1 952.9 345.9 1298.8 4. 78 4.71 9.49 3, 27 12.76 10.. 24 2 1030.8 384.2 1415.. 0 5.10 4.89 9.99 4.00 13.99 10. 31 3 1046.0 534.0 1580.0 5.10 6.59 11.69 4.00 15.69 10.34 4 1057.7 809.9 1867.6 5.10 8.01 13.11 4.00 17.11 9.54 5 1080.3 1085.4 2165.. 7 5.10 8.83 13. 93' 4.00 17.93 8. 63 6 1337.1 1151.5 2488.6 7.02 10.24 17.26 4. 60 21.86 9. 15 7 1357.7 1494.5 2852.2 7.02 11.36 18,38 4. 60 22.98 8. 39 I 8 1636.3 1599.'3 3235.6 7.02 13.22 20.24 4. 60 24.84 8. 00 r w 9 1646.7 2028.3 3675.0 7.02 14.59 21.61 4. 60 26.21 7.43 4 I 1970 2488.1 1640.8 4128.9 12.36 13,36 25.72 4. 67 30.39 7. 67 1 2505.5 2128.0 4633.5 12.36 16.51 28.87 4. 67 33.54 76 54 2 2935.6 2247.9 5183.5 13.44 16.90 30.34 4. 67 35.01 7. 03 3 2958.6 2829.9 5788.5 13.44 20.36 33,80 4. 67 38.47 6. 92 4 3194.8 3244.2 6439.0 15.85 21.67 37.52 4.74 42.26 6. 84 5 3220.4 3940.0 7160.4 15.85 25.49 41.34 4.74 46.08 6.70 6 3316.9 4624.5 7941.4 17.67 27. 65 45.32 4.88 50.20 6. 58 7 3757.9 5035.7 8793.6 20.47 30.57 51.04 4.88 55.92 6. 63 8 3777.1 5933.9 9711.0 20.47 35.03 55.. 50 5.02 60.52 6. 50 9 3790.7 6917.6 10708.3 20.47 41.42 61.89 5.02 66.91 6.51. 1980 3800.9 7991.4 11792.3 20.47 48.11 68.58 5. 38 73.96 6.54

/1 - Thermal costs in Nova Scotia have been computed using anticipated New Brunswick costs, - - The cost of transmission in Nova Scotia is not included. !? - The effects of flow regulatjon at Rankin Rapids from 1968 onwards are included at no cost. 14 - In computing unit energy costs, annual generation has been reduced by 4 per cent, to take account of transmission losses - 138 -

TABLE 60

COMPARISON BETWEEN COSTS OF HYDRO-ELECTRIC GENERATION ON THE SAINT JOHN RIVER AND THE COSTS OF EQUIVALENT THERMAL GENERATION

CASE III(b) SEQUENCE - YEAR 1980

D evelonment Grand Falls Item Unit Mactaquac Extension Morrill Number of units - 8 6 4 Net capability Mw 41 4 289 * 98 Annual average energy available from total river flow at site Million kwh 1,707 1, 0142% 494 Total annual average firm energy generation Million kwh 1, 610 977 * 45 1

Utilization of available energy Per cent 94. 6 96.3 $6 91.3 Capacity factor Per cent 44.5 38-5* 52.5 Estimated capital cost Million dollars 123.6 49.8 40.4 Total annual charges Million dollar s 8.824 3.740 2.804

Average cost of energy and associated capacity at site Mills/kwh 5-48 7.51 6. 22

Cost of equivalent thermal energy and capacity at site Mills / kwh 6.50 9. 15 5,96

'k These figures apply to the total installation at the Grand Falls plant. Energy generated by the extension can be estimated approximately by subtracting the average annual energy generated at the existing Grand Falls development in Case I for the year 1980, namely, 478 million kilowatthour s from the total annual average .firm energy generation. The net capability of the six-unit extension is 229 megawatts, - 139 -

Case III( c)' Sequence - When the Rankin Rapids development is operated to meet a load in Maine,without consideration of downstream energy requirements, a situation can arise in which water is being withdrawn from storage at Rankin Rapids tomeet the load in Maine at the same time that water is being spilled at the downstream plants due to the lack of sufficient firm energy demand. Situations of this type canbe avoidedby interchange of energy between the utilities in New Brunswick and Maine. Revised annual computations were therefore made using the economic sequences determined for Case III(b) but with the following changes in governing conditions:

(i) - Interconnection is established at 138 kv between The New Brunswick Electric Power Commission system and a utility system in Maine which includes the Rankin Rapids storage and power development and 150 megawatts of thermal generation.

(ii) - The Rankin Rapids development is commissioned in 1968 with a total installation of 200 megawatts and is operated in conjunction with 150 megawatts of thermal generation in Maine and with the utility systems in New Brunswick and Nova Scotia to meet

the combined New Brunswick-Nova Scotia ' loads, and a load in Maine. The combined system is operated in accordance with the criteria described in' Section .7.2 of this report.

The results of these annual runs are presented in Table 61, and on Plate 24, and the cost comparison with equivalent thermal generation is given in Table 62. The effect of transmission interconnection is reflected in the figures of increased percentage utilization of potential at-site energy when compared with corresponding figures for Case III(b) sequence. TABLE 61

CASE III( C) - AVERAGE ANNUAL ENERGY GENERATION AND COSTS IN NEW BRUNSWLCK AND NOVA SCOTIA

Annual Generation Unit Energy Million Kwh Annual Costs - Million Dollars Cost,A Year Hydrok Thermal Total Hydro Thermal!! Subtotal TransmissionE Total Mills/Kwh

1960 934.1 259.0 1193.1 4.78 3.86 8. 64 3.15 11.79 10.29 1 952.9 345.9 1298.8 4. 78 4.71 9.49 3.27 12.76 10.24 2 1030.8 384.2 1415.0 5.10 4.89 9.99 4.00 13.99 10.31 3 1046.0 534.0 1580.0 5.10 6.59 11.69 4.00 15.69 10.34 4 1057.7 809.9 186'1.6 5.10 8.01 13.11 4.00 17.11 9.54 5 1080.3 1085.4 2165.7 5.10 8.83 13.93 4.00 17.93 8. 63 6 1337.1 1151.5 2488.6 7.02 10.24 17.26 4. 60 21.86 9. 15 I 7 1357.7 1494.5 2852.2 7.02 11.36 18.38 4.60 22.98 8. 39 Y 8 1744.4 149L 2 3235.6 7.02 12.86 19.88 4. 60 24.48 7.88 1745.3 3675.0 7.02 14.24 21.26 4. 60 25.88 9 1929.7 7,33 I 1970 2635.6 1493.3 4128.9 12.36 12.88 25.24 4. 67 29.91 7.55 1 2637.0 1996.5 4633.5 12.36 16.11 28.47 4. 67 33,14 7.45 2 3164.8 2018.7 5183.5 13.44 16.17 29.61 4. 67 34.28 6. 89 3 3169.5 2619.0 5788.5 13.44 19.70 33.14 4. 67 37.81 6, 80 4 3373.8 3065.2 6439.0 15.85 21.08 36.93 4.74 41.67 6.74 5 3383.1 3777.3 7160.4 15.85 24.97 40.82 4.74 45.56 6. 63 6 3431.0 4510.4 7941,4 17.67 27.24 44.91 4.88 49.79 6-53 7 3911.5 4882.1 8793.6 20.47 30.07 50.54 4.88 55.42 6.56 8 3919.4 5791.6 9711.0 20.47 34.57 55.04 5.02 60.06 6.44 9 3927.1 6781.2 10708.3 20.47 .41.00 61.47 5.02 66.49 6,47 1980 3929.9 7862.4 11792.3 20.47 47.71 68. 18 5.38 73.56 6.. 50

/1- - Thermal costs.in Nova Scotia have been computed using anticipated New Brunswick costs. -12 - The cost of transmission in Nova Scotia is not included. -/3 - The effects of flow regulation at Rankin Rapids from 1968 onwards are included at no cost. -/4 - In computing unit energy costs, annual generation has been reduced by 4 per cent, to take account of tr ansmi s s ion los s e s - 141 -

TABLE 62

COMPARISON BETWEEN COSTS OF HYDRO-ELECTRIC GENERATION ON THE SAINT JOHN RIVER AND THE COSTS OF EQUIVALENT THERMAL GENERATION

CASE III(c) SEQUENCE - YEAR 1980

Development Grand Falls Item Unit Mactaquac Extension Morrill

Number of units - 8 6 4

Net capability Mw 414 289 f 98 Annual average energy available from total river flow at site Million kwh 1,721 995 :: 51 1

Total annual average firm energy generat ion Million kwh 1,651 97 8 487 Utilization of available energy Per cent 95.9 98. 5:% 95.4

Capacity factor Per cent 45.5 38.5 % 56. 6 Estimated capital cost Million dollars 123.6 49.8 40-4

Total annual charges Million dollar s 8.824 3.740 2. 80.4

Average cost of energy and associated capacity at site Mill s / kwh 5. 36 7*49 5-78

Cost of equivalent thermal energy and capacity at site Mills/kwh 6. 40 9.15 5.78

f These figures apply to the total installation at the Grand Falls plant. Energy generated by the extension can be estimated approximately by subtracting the average annual energy generated at the existing Grand Falls development in Case I for the year 1980, namely, 478 million kilowatthours from the total annual average firm energy generation. The net capability of the six-unit extension is 229 megawatts. - 142 -

The change in the pattern of outflow from theRankinRapids develop-

ment following transmission interconnection is illustrated on Plate 25, which

shows monthly outflows fromRankinRapids for Case III(b) and for Case III(c)

sequences. In Case III(c.) sequence, storage withdrawals are low during the

spring floodwhenthe uncontrolledflows at the power developments downstream

are high. On the other hand, there is an increase in outflow during the summer

months when the uncontrolledflows at plants downstream are comparatively low.

8.4 - Case IV Sequences

As explained under Section 1.2 - Scope of Study, the Passamaquoddy

Tidal Power Project and the Rankin Rapids Auxiliary are economically justi-

fied if built entirely by the United States at an interest rate of 2-1/2 per cent.

The effects of possible variations in the control of Rankin Rapids storage when

operated to firm up output from the tidal project, were therefore studied.

As a first step, a series of computer runs was made to find the

optimum amount of ther-malpower neededfor operation with the Rankin Rapids

development and the Passamaquoddy Tidal Power Project to obtain maximum

energy output. In this case, the net capability of the Rankin Rapids develop-

ment was taken as 460 megawatts as proposedbytheInternationalPassamaquoddy

. Engineering Board.

The results obtained are presented on Plate 26, and are very

similar to those for Case 111. Maximum energy output from the Rankin Rapids

development amounts to 1, 267 million kilowatthours and is obtainable by - 143 -

integrated operation with thermal generation of about 150 megawatts. The minor differences in the figures of maximum output in Cases 111 and IV are attributable to the change in pattern of storage release consequent upon the addition of the Passamaqu.oddy Tidal Power Project in Maine. However, this difference is small and will not affect the economic sequences of power development downstream as determined for the alternative conditions in Case

111. The average difference in the pattern of outlfow from the Rankin Rapids development can be seen by comparing the hydrographs of average monthly flow given on Plates 25 and 27.

Case I11 showed the effects of Rankin Rapids storage on power developments downstream. The inclusion of the Passamaquoddy Tidal Power

Project supplying a load in Maine will have no effect on the economic sequences determined for Case 111. Therefore, the studies under Case IV sequences merely involved a repeat of the annual runs for Case I11 sequences, using a slightly different pattern of outflow from the Rankin Rapids development. The results of these runs for Cases IV(a), JIV(b), and IV(c), are presented in

Tables 63, 65, and 67, respectively, and plotted on Plates 28, 29, and 30.

Comparisons between the costs of hydro-electric generation on the Saint

John River and the costs of equivalent thermal generation are given in Tables

64, 66, and 68. TABLE 63 .

CASE IV(a) - AVERAGE ANNUAL ENERGY GENERATION AND COSTS IN NEW BRUNSWICK AND NOVA SCOTIA

Annual Generation Unit Energy Million Kwh Annual Costs Millicm Dollars - cost-14 Year Hydro!? Thermal Total Hydro ThermalL Subtotal Transmission!? Total MillslKwh 1960 934.1 259.0 1193. 1 4.78 3.86 8. 64 3. 15 11.79 10.29 1 952.9 345.9 1298.8 4. 78 4.71 9.49 3.27 12.76 10.24 2 1030.8 384.2 1415.0 5.10 4.89 9.99 4.00 13.99 10.31 3 1046.0 534.0 1580.0 5.10 6.59 11.69 4.00 15.69 10.34 4 1057.7 809.9 1867. 6 5.10 8.01 13.11 4.00 17.11 9.54 5 1080. 3 1085.4 2165.7 5.10 8. 83 13.93 4.00 17.93 8. 63 6 1796.2 692.4 2488.6 10.44 8.76 19.20 4. 67 23.87 9.99 7 1832.2 1020.0 2852.2 10.44 9.82 20.26 4. 67 24.93 9.10 1 8 2081.3 1154.3 3235.6 10.44 11.81 22.25 4. 67 26.92 8. 67 P tb 9 2338. 3 1336.7 3675.0 10.97 12.39 23.36 4. 67 28.03 7.95 tb t 1970 2501.7 1627.2 4128.9 11.56 13.31 24.87 4. 67 29.54 7.45 1 2612.1 2021.4 4633.5 12.22 16.18 28.40 4.71 33.11 7.44 2 2690.3 2493.2 5183.5 12.78 17.67 30.45 4.71 35.16 7. 06 3 2707.9 3080.6 5788.5 12.78 21.14 33.92 4.71 38.63 6.95 4 2720.7 3718.3 6439.0 12.78 24.79 37.57 4.71 42.28 6. 84 5 2831.2 4329.2 7160.4 14.06 28.36 42.42 4.93 47.35 6. 89 6 3275.7 4665.7 7941.4 16.72 29.41 46.13 5.07 51.20 6. 72 7 3290.8 5502-8 8793.6 16.72 33.68 50.40 5.07 55.47 6.57 8 3302.7 6408.3 9711.0 16.72 39.84 56.56 5.44 62.00 6. 65 9 3311.3 7397.0 10708. 3 16.72 44.59 61,31 5,44 66.75 6.49 1980 3359.2 8433. 1 11792.3 17.80 47.80 65.60 5.44 71.04 6. 28

/1 - Thermal costs in Nova Scotia have been computed using anticipated New Brunswick costs. !? !? - The cost of transmission in Nova Scotia is not included. !? - The effects of flow regulation at Rankin Rapids from 1968 onwards are included at no cost. !? - In computing unit energy costs, annual generation has been reduced by 4 per cent, to take account of transmission 10s ses. - 145 -

TABLE 64

COMPARISON BETWEEN COSTS OF HYDRO-ELECTRIC GENERATION ON THE SAINT JOHN RIVER AND THE COSTS OF EQUZVALENT THERMAL GENERATION

CASE W(a) SEQUENCE - YEAR 1980

Grand Falls Item Unit Mactaqua c Extension

Number of units - 8 6 Net capability MW 41 4 289 * Annual average energy available from total river flow at site Million kwh 1,705 1, 015*

Total annual average firm , energy generation Million kwh 1, 611 9869;

Utilization of available energy Per cent 94.5 97.2* Capacity factor Per cent 44. 5 38.8 * Estimated capital cost Million dollars 123. 6 49.8

Total annual charges Million dollars 8.955 3.740 Average cost of energy and associated capacity at site Mills / kwh 5.55 7.37

Cost of equivalent thermal energy and capacity at site Mills/kwh 6.50 9. 05

:K These figures apply to the total installation at the Grand Falls plant. Energy generated by the extension can be estimated approximately by subtracting the average annual energy generated at the existing Grand Falls development in Case 9 for the year 1980, namely, 478 million kilowatthours from the total annual average firm energy generation. The net capability of the six-unit extension is 229 megawatts. TABLE 65

CASE IV(b) - AVERAGE ANNUAL ENERGY GENERATION AND COSTS IN NEW BRUNSWICK AND NOVA SCOTIA

Annual Generat ion Unit Energy Million Kwh Annual Costs - Million Dollars cost, 14 Year Hydro!? Thermal Total Hydro ThermalE Subtotal Transmission!? Total Mills /Kwh 1960 934.1 259.0 1193.1 4. 78 3.86 8. 64 3.15 11.79 10.29 1 952.9 345.9 1298.8 4. 78 4.71 9.49 3.27 12.76 10.24 2 1030.8 384.2 1415.0 5.10 4.89 9.99 4.00 13.99 10.31 3 1046.0 534.0 1580.0 5.10 6.59 11.69 4.00 15.69 10.34 4 1057.7 809.9 1867.6 5.10 8. 01 13. I1 4. 00 17.11 9.54 5 1080.3 1085.4 2165.7 '5.10 8.83 13.93 4.00 17.93 8. 63 6 1337.1 1151.5 2488.6 7.02 10.24 17.26 4. 60 21.86 9. 15 7 1357.7 1494.5 2852.2 7.02 11.36 18.38 4. 60 22.98 8.39. 8 1636.3 1599.3 3235.6 7.02 13.22 20.24 - 4. 60 24.84 8. 00 1 9 1646.7 - 2028.3 3675. 0 7.02 14.59 21.61 4,60 26.21 7.43 w 1970 2487.0 1641.9 4128.9 12.36 13.36 25.72 4. 67 30.39 7. 67 1 2504.4 2129.1 4633.5 12.36 16.51 28.87 4. 67 33.54 7.54 1 2 2937.4 2246.1 5183.5 13.44 16.89 30.33 4. 67 35.00 7. 03 3 2960.3 2828.2 5788.5 13.44 20.35 33.79 4. 67 38.46 6.92 4 3198.2 3240.8 6439. 0 15.85 21.66 37.51 4.74 42.25 6. 83 5 3223.2 3937.2 7160.4 15.85 25.48 41.33 4.74 46.07 6. 70 6 3316.6 4624.8 7941.4 17. 67 27.65 45.32 4. 88 50.20 6. 58 7 3759.4 5034.2 8793.6 20.47 30.57 51.04 4. 88 55.92 6. 62 8 3778.5 5932.5 9711. 0 20.47 35.02 55.49 5,02 60.51 6.49 9 3792.3 6916.0 10708.3 20.47 41.42 61.89 5.02 66.91 6. 51 1980 3802.9 7989.4 11792.3 20.47 48.11 68.58 5.38 73.96 6.53 !1 - Thermal costs in Nova Scotia have been computed using anticipated New Brunswick costs. /z - The cost of transmission in Nova Scotia is not included. !? - The effects of flow regulation at Rankin Rapids from 1968 onwards are included at no cost. !! - In computing unit energy costs, annual generation has been reduced by 4 per cent, to take account of transrnis sion 10s seso - 147 -

TABLE 66

COMPARISON BETWEEN COSTS OF HYDRO-ELECTRIC GENERATION ON THE SAINT JOHN RIVER AND THE COSTS OF EQUIVALENT THERMAL GENERATION

CASE IV(b) SEQUENCE - YEAR 1980

D eveloDment Grand Falls item Unit Mactaquac Extension Morrill

Number of units - 8 6 4 Net capability Mw 414 289 :> 98 Annual average energy available from total river flow at site Million kwh 1,705 1, 015+ 49 5 Total annual average firm energy generation Million kwh 1,609 979 f 45 3 Utilization of available energy Per cent 94.4 96.5 ::: 91.5

Capacity factor Per cent 44.5 38.5 52.6 Estimated capital cost Million dollars 123.6 49.8 40.4

Total annual charges Million dollars 8.824 3.740 2.804 Average cost of energy and associated capacity at site M.ills / kwh 5.49 7.48 6. 19

Cost of equivalent thermal energy and capacity at site Millslkwh 6.50 9.13 5.95

* These figures apply to the total installation at the Grand Falls plant. Energy generated by the extension can be estimated approximately by subtracting the average annual ener’gy generated at the existing Grand Falls development in Case I for the year 1980, namely, 478 million kilowatthour s from the total annual average firm energy generation. The net capability of the six-unit extension is 229 megawatts. TABLE 67

CASE IV( C) - AVERAGE ANNUAL ENERGY GENERATION AND COSTS IN NEW BRUNSWICK AND NOVA SCOTIA

Annual Generation Unit Energy Million Kwh Annual Costs - Million Dollars cost-i4 Year Hydroe Thermal Total Hydro Thermalb Subtotal Transmiss ionl;! Total MillslKwh 1960 934.1 259.0 1193. 1 4. 78 3.86 8. 64 3. 15 11.79 10.29 1 952.9 345.9 1298.8 4. 78 4. 71 9.0 49 3. 27 12.76 10.24 2 1030.8 384.2 1415.0 5.10 4. 89 9.99 4.00 13.99 10.31 3 1046.0 534.0 1580.0 5.10 6.59 11.69 4. 00 15.69 10.34 4 105.7.7 809.9 1867. 6 5.10 8.01 13.11 4. 00 17.11 9.54 5 1080.3 1085.4 2165.7 5.10 8. 83 13.93 4.00 17.93 8. 63 6 1337.1 1151.5 2488. 6 7.02 10.24 17.26 4.60 21.86 9. 15 7 1357.7 1494.5 2852.2 7.02 11.36 18.38 4. 60 22.98 8. 39 8 1744.4 1491.3 3235.7 7.02 12.86 19.88 4. 60 24.48 7. 88 1 7.02 14.24 21.26 60 9 1745. 3 1929.7 3675.0 4. 25.88 7.33 r P 1970 2621.5 1507.4 4128.9 12.36 12.91 25.27 4. 67 29.94 7.55 Q3 1 2619.2 2014.3 4633.5 12.36 16.16 28.52 4. 67 33.19 7.46 1 2 3173.2 2010.3 5183.5 13.44 16.16 29.60 4. 67 34.27 6. 88 3 3180.9 2607.6 5788.5 13.44 19.67 33.11 4. 67 37.78 6. 80 4 3381.4 3057.6 6439.0 15.85 21.10 36.'95 4.74 41.69 6.74 5 3393.4 3766.6 7160.4 15.85 24.95 40.80 4.74 45.54 6. 62 6 3437.4 4504.0 7941.4 17.67 27.25 44. 92. 4. 88 49.80 6.53 7 3912.1 4881.5 8793.6 20.47 30.09 50.56 4.88 55.44 6.57 8 3918.9 5792.1 9711.0 20.47 34.58 55.05 5.02 60.07 6. 44 9 3931.5 6776.8 10708.3 20.47 40.97 61.44 5.02 66.46 6. 46 1980 3904.5 7887.8 11792.3 20.47 47.79 68.26 5.38 73.64 6. 50

!? - Thermal costs in Nova Scotia have been computed using anticipated New Brunswick costs. -12 - The cost of transmission in Nova Scotia is not included. !? - The effects of flow regulation at Rankin Rapids from 1968 onwards are included at no cost. !?! !?! - In computing unit energy costs, annual generation has been reduced by 4 per cent, to take account of transmission 10s se s - 149 -

TABLE 68

COMPARISON BETWEEN COSTS OF HYDRO-ELECTRIC GENERATION ON THE SAiNT JOHNRIYER AND THE COSTS OF EQUIVALENT THERMAL GENERATION

Development Grand Falls Item Unit Mactaquac Extension Morrill Number of units - 8 6 4 Net capability Mw 414 2.89 * 98

Annual average energy available . from total river flow at site e Million kwh 1,721 1, 001 96 49 9 Total annual average firm energy generation Million kwh 1, 655 987 $: 47 6

Utilization of available energy Per cent 96.2 98.61% 95.5 Capacity factor Per cent 45.5 38.9 + 55.5 Estimated capital cost Million dollars 123.6 49.8 40.4

Total annual charges Million dollar s 8.824 3.740 2.804 Average cost of energy and associated capacity at site Mills/kwh 5.34 7.35 5.90 Cost of equivalent thermal energy and capacity at site Mills / kwh 6.40 9.05 5.81

* These figures apply to the total installation at the Grand Falls plant. Energy generated by the extension can be estimated approximately by subtracting the average annual energy generated at the existing Grand Falls development in Case I for the year 1980, namely, 478 million kilowatthour s from the total annual average firm energy generation. The net capability of the six-unit extension is 229 megawatts. TABLE 69

COMPARISON OF SYSTEM COSTS IN NEW BRUNSWICK AND NOVA SCOTIA FOR CASE I AND CASE I1 SEQUENCES

1 2 3 4 5 6 7 8

Annual Costs Case I Annual Costs Difference Energy Costs for /2 N. B. N. S. Total Case I1 4-5 Combined Systems-. Million Million Million Million Million Case I Case I1 Year Dollar s Dollar s /1 D ollhr s Dollar s Dollars Mills /Kwh Mills /Kwh 1960 11.79 .. 11.79 11.79 - 10.29 10.29 1 12.76 - 12.76 12.76 - 10.24 10.24 2 13.99 - 13.99 13.99 10.31 10.31 3 14.83 0. 87 15.70 15.69 0.01 10.34 10.34 4 15.26 1.85 17.11 17.11 9.54 9.54 5 15.75 2.35 18.10 17.93 0. 17 8.71 8. 63 6 17.39 4.12 21.51 23.87 -2.36 9.00 9.99 7 17.95 4.72 22.67 24.93 -2.26 8.28 9.10 1 8 21.90 6. 96 28.86 27.64 1.22 9.29 8.90 w ur 9 22.37 7. 67 30.04 28.89 1.15 8.51 8.19 0 1970 22.93 8.43 31.36 30.48 0. 88 7.91 7.69 1 1 23.64 10.93 34.57 34.06 0.51 7.77 7.66 2 24.98 11.83 36.81 36.12 0. 69 7.40 7.26 3 27.67 12.84 40.51 39.58 0.93 7.29 7.12 4 28.56 15.60 44.16 43.22 0.94 7. 14 6.99 5 29.61 18.37 47.98 48.25 -0.27 6.98 7.02 6 32.23 19.79 52.02 52.44 -0.42 6.82 6.88 7 34.79 22.89 57.68 56.70 0.98 6.83 6.72 8 37.88 26.07 63.95 63.21 0.74 6.86 6.78 9 39.26 29.44 68.70 67.95 0.75 6.68 6. 61 1980 42.44 32.92 75.36 72.14 3.22 6. 66 6.36

!1 - Thermal costs in Nova Scotia were computed using anticipated New Brunswick costs.

!? - The cost of future transmission requirements in Nova Scotia is not included.

.. ! - 151 -

9 - COMPARISON OF SEQUENCES

As was explained in Section 8 of this report, the sequence studies were made using a fuel cost of 35 cents per million Btu at the burner, and an interest rate of 5.5 per cent which was applied regardless of the schedule of borrowing required. All of the comparisons made in this section mustbe regarded in this light. It is believed that these assumptions regarding interest rate and fuel cost provide anadequate basis for answering f%e questions posed by the Terms of Reference.

Cases I and I1 are two possible sequences of power development inNew Brunswickwithout storage at RankinRapids, and differ only in the extent of future energy interchange between New Brunswick and Nova Scotia. In

Case I, the interconnecting transmission lines between the provinces are utilized for sharing of spare capacity and spinning reserve only; in Case 11, it

is assnedthat energywill be interchanged to give the lowest possible power

costs on both systems. System costs for the economic sequences of development of Cases I and II are presected in Table 69 on page 150. In order to

bring these costs to a comparable basis, it is necessary to add the cost of

incremental thermal generation in Nova Scotia to the annual charges in New

Brunswick for Case I, toobtainthe totais given in column 4. These figures

may then be compared directlywith the annual charges for Case I1 sequence

as given in column 5. The differences given in column 6 are the total savings

in New Brunswick and Nova Scotia associated with the Case I1 sequence. It - 152 -

should be noted that in the years 1966, 1967, 1975, and 1976, annual .charges for Case I1 sequence are greater than the corresponding figures for Case I sequence. These reversals in the long-term trend occur during periods of load buildup on hydro-electric developments on the Saint John River. The reversal in 1980 results from a variation in the totalinstalledcapacities at that time.

The interchange of energy between the utilities in New Brunswick andNovaScotia in Case I1 results in accelerated development of hydro-electric stations on the Saint JohnRiver and gives an apparent overall cost benefit.

The Case I1 sequence was thereforeused as a basis for comparisonwith other sequences including a storage and power development at Rankin Rapids.

The Mactaquac development and the Grand Falls extension were included in all sequences, except Case I, to their approximate ultimate net capabilities of 414megawatts and 229 megawatts respectively. The Beechwood development was included in all sequences to its economic limit of capability, namely, 101 megawatts, as already planned. A comparison of the various

sequences, therefore, will give the detailed effects of Rankin Rapids storage on energy generation at the Beechwood and Mactaquac developments and at the Grand Falls extension.

On the basis of the assumptions made in connection with interest

rates and fuel cost, the economy of the Morrill development is marginal, and

it was included only in those sequences in which theRankin Rapids development is constructed. A comparison of sequences will not, therefore, give - 153 -

the effects of Rankin Rapids storage on energy generation at the Morrill development *

The long-term effects of Rankin Rapids storage depend, among other things, on the volume of that storage and on the ultimate capacity at the plants downstream. It was found in the sequences that these variables are essentially independent, and the development and operation of storage at the Rankin Rapids site will not change the ultimate capacities at developments downstream. These capacities are determined primarily by the economics of peak power generation in New Brunswick, and may be influenced to some extent by limitations of headpond and tailwater fluctuations

If the Passamaquoddy Tidal Power Project is developed, the varying output from the Rankin Rapids development will cause a fluctuation in the

Grand Falls forebay which can be superimposed upon the fluctuation resulting from peak load operation of that plant. Similarly, when the Mactaquac development is operated as a peaking plant, there will be significant fluctuations in the tailwater elevation at that plant, A detailed study of these effects will be required before a final choice of the installed capacity of the Mactaquac development and of the Grand Falls extension, can be made. However, what- ever these capacities may be, minor changes in installation at these developments will not significantly alter the long-term effects of Rankin Rapids storage on energy generation as determined in the system studies.

By the year 1980, the ultimate installations at the Mactaquac development and at the Grand Falls extension, were reached in all sequences - 154 -

except Case I, and a direct comparison of the value of each of these developments in the various sequences at that time is made in Tables 70 and 71.

Both developments show a benefit-cost ratio greater than one in Case 11

sequence where the Rankin Rapids development is not constructed. In all

other sequences which include the Rankin Rapids development, there is an

increase in the benefit-cost ratio. The cost figures given in these tables will

remain constant after the year 1980 and, therefore, will apply over the major

portion of the economic life of these developments. Prior to the year 1980,

the benefit-cost ratios will be less than the figures given in the tables but will be greater than one.

In the case of the Morrill development with a net capability of only

98 megawatts, the benefit-cost ratio varies between 0.96 and 1. 00. If addi-

tional units were installed for peaking capacity, if a lower interest rate is

used, or if fuel costs should rise, the benefit-cost ratio will increase. It is

apparent that the Morrill development should not be constructed until after

the Mactaquac development and the Grand Falls extension, and that its economy

must be re-examined when more detailed information is available with regard

to trends in interest rates and fuel costs.

Tables 72 and 73 on page 167, contain the detailed comparisons

between annual costs and average annual hydro- electric energy generation

for all of the sequences considered. Table 72 shows the comparison between

Case I1 and the sequences of Case I11 in which the Passarnaquoddy Tidal

Power Project is not constructed. Table 73 shows the same comparison - 155 -

TABLE 70

COMPARISON OF 1980 COSTS FOR THE MACTAQUAC DEVELOPMENT IN CASES 11, 111, AND IV SEQUENCES

8 Units - 414 Megawatts Net CaDabilitv

~ ~~ ~ ~-~ - At Site Equivalent Annual Energy Thermal Charges-/1 cost Power Costs Benefit-Cost Sequence lo6 Dollars Mills/Kwh Mills/Kwh Ratio I1 8.955 6. 10 6. 80 1.11 III( a) 8.955 5.56 6.50 1. 17 III(b) 8.824 5.48 6.50 1. 19 III( c) 8.824 5.36 6.40 1. 19 Wa) 8.955 5.55 6.50 1. 17 Wb) 8.824 5.49 6.50 1. 18 IV( c) 8.824 5.34 6. 40 1,20

-/1 - Annual charges for the Mactaquac development vary as a result of changes in the period of installation of units.

TABLE 71

COMPARISON OF 1980 COSTS FOR THE GRAND FALLS EXTENSION IN CASES 11. 113. AND 3V SEUUENCES

6 Units - 229 Megawatts Net Capability

At Site Equivalent Annual Energy Thermal Charges cost Power Costs Benefit-Cost Seauence lo6 Dollars Mills/Kwh Mills/Kwh ’ Ratio I1 3.740 9. 63 10.90 1. 13 III(a) 3.740 7.40 9. 06 1.22 III(b) 3.740 7.51 9. 15 1.22 III( c) 3.740 7.49 9. 15 1.22 Wa) 3.740 7.37 9. 05 1. 23 Wb) 3.740 7.48 9. 13 1.22 WC) 3.740 7.35 9.05 1.23 - 156 -

using Case IV sequences in which the Passamaquoddy Tidal Power Project is commissioned in the year 1970. As the figures in both tables are almost identical, the detailed discussion will be confined to the comparison of Cases

I1 and I11 sequences as given in Table 72.

Columns 1 and 2 of Table 72, give the total annual charges and the annual hydro energy generation as determined year by year for Case II.

Corresponding figures for Cases III(a) and III(b) are given in columns 3 and

4, and in columns 5 and 6, respectively. The remaining columns give the differences in total annual charges and annual hydro energy generation between the various sequences, as indicated at the head of each column.

Cases I1 and III(a) have the same sequence of installation of generating facilities and differ only in that the storage at Rankin Rapids development is utilized from 1968 onwards in Case III(a) to give increased hydro energy generation at plants downstream. The differences in total annual costs and annual hydro energy generation between Cases I1 and III(a) as given in

Table 72, are solely the result of regulation provided by Rankin Rapids storage.

With the commissioning of the Rankin Rapids development in 1968, a total energy benefit averaging 226.5 million kilowatthours is obtained immediately at the Mactaquac and Beechwood developments. This benefit increases steadily as the load demand in New Brunswick increases, and as additional units are added at the Mactaquac development, until the year 1972 when six units have been installed. The addition of a thermal-electric plant in New Brunswick in the year 1973 makes only a small difference in this energy benefit. However, when Units 7 and 8 are installed at the Mactaquac development in 1975, the energy benefit from Rankin Rapids decreases, as a greater proportion of the unregulated flow of the river which occurs in

Case I1 canbe utilized at this time by the higher installation at the Mactaquac site.

When the first four units of the Grand Falls extension are added in Case III(a) in 1976, the energy benefit from Rankin Rapids increases considerably. However, with the installation of Units 5 and 6 in the extension in 1980, the energy benefit decreases for the same reason as at the Mactaquac development

The accumulated reductions in total annual charges of Case I1

sequence, up to and including the year 1980, consequent upon developing and utilizing storage at the Rankin Rapids site under Case III(a) sequence, amount to 13. 25 million dollars. After 1980, the annual benefit will continue at the

rate of 1. 1 million dollars per year throughout the economic life of the power

developments downstream.

In the sequences of Gases I1 and III(a), the energy benefit is ob-

tained at the Mactaquac and Beechwood developments and at the Grand Falls

extension, by developing and operating storage at Rankin Rapids. There is,

however, an additional effect associated with this storage in that the program

of power development on the Saint John River in New Brunswick can be ad-

vanced. The value of this effect is obtained from a comparison of Cases

III(a) and III(b). The differences in total annual charges for these sequences

represent an additional benefit to New Brunswick. - 158 -

Total annual costs and annual hydro-electric energy generation in Cases III(a) and IlCI(b) are given in Table 72. In Case III(b), the Grand

Falls development is installed in the year 1966 in anticipation of the availability of Rankin Rapids storage in 1968, at which time the four units installed at Grand Falls extension can be utilized for firm power generation. This is in direct contrast with Case III(a) in which the firm power output of the Grand

Falls extension was limited in the early stages of the sequence and where, in consequence, the Mactaquac development was constructed first.

Referring to the last two columns of Table 72, there is an immediate monetary advantage in adding units to the existing Grand Falls development in the ye,ar 1966, although annual hydro energy generation is reduced by 459.1 million kilowatthours per year. However, by the year 1970 in Case III(b), it is economic to develop the Mactaquac site with the result that hydro-electric energy generation in both sequences becomes practically the same. In addition, the total annual charges for Case III(b) are increased to a value slightly greater than for Case III(a).

In 1972, the Mactaquac installation in Case III(b) is increased to a point where significant additional energy benefits are obtained from the

Rankin Rapids storage, annual charges for both sequences being approximately equal, A further increase in hydro-electric energy generation occurs in 1974 when the Mactaquac development is extended to its ultimate capacity in Case

III(b) a - 159 -

In the year 1976, the amount of hydro-electric generation on the

Saint John River included in both sequences is the sarne, except that Units

5 and 6 in the Grand Falls extension are not installed in Case III(a). The difference in hydro-electric energy generation is therefore very small. At this point, the picture becomes complicated in that the Morrill development was added in Case III(b) in the year 1977. As the economy of this development, based on the assumptions used in the studies, is marginal, the additional hydro-electric energy generated at the development, was subtracted to give a clearer picture of the effects of Rankin Rapids storage in accelerating development of the Mactaquac site and the Grand Falls extension.

Energy generation at Morrill is removed from Case III(b) for the years 1977 to 1980 inclusive, in Table 74. It can be seen that when the ultimate installations at the Mactaquac development and the Grand Falls extension are reached in the year 1980, the difference in hydro-electric energy generation is approximately zero. Thereafter, there are no further benefits at Grand

Falls, Beechwood and -Mactaquac attributable to storage at Rankin Rapids 02 account of accelerated development of the power potential of the Saint John

River in New Brunswick.

The differences in annual charges between Cases III(b) and III(a)

as given in Table 72, fluctuate considerably from year to year, primarily be-

cause of the variation in available spare capacity in each sequence as integral numbers of units are added at the hydro-electric developments and at thermal

stations. These variations are more or less random and hence cancel each - 160 -

TABLE 74

REVISED ENERGY FIGURES FOR CASE III(b) SEQUENCE WITH MORRILL DEVELOPMENT EXCLUDED

~ ~ ~~ ~ Annual Hydro-Electric Energy Generation - 106 Kwh Mor r ill Year Case III(b) Development Case III(a) Difference (1) (2) (3) t 1)-(2)-(3) 1977 3757.9 449.3 3291.2 17.4 1978 3777.1 450.0 3303.0 24. 1 1979 3790.7 450.4 3311.6 28. 7 1980 3800.9 450.6 3358.8 -8. 5

other out to some extent. The approximate accumulated benefit attributable to storage at Rankin Rapids on account of accelerated development of the downstream power potential in Case III(b) sequence, amounts to 9.1.3 million dollars, excluding the minor benefits in theyear.s 1977 to 1980 inclusive.

After 1980, there are no further benefits of this type.

The inclusion of the Passamaquoddy Tidal Power Project in the utility system in Maine makes very little change in the benefits associated with storage at the Rankin Rapids development. If the Morrill development is excluded, the accumulated reductions in total annual charges of Case I1 sequence up to, and including, the year 1980, consequent upon developing and utilizing storage at the Rankin Rapids site under the conditions of Case IV(a) sequence, amount to 13. 20 million dollars. After 1980, the annual benefit will continue at the rate of 1.1 million dollars per year throughout the economic life of the power developments downstream. The latter amount is identical with the figure obtained by comparing Cases I1 and III(a) as previously de-

scribed.

Again the differences in annual charges between Cases IV(a) and

IV(b) as giveninTable 73, fluctuate considerably from year to year, primarily

because of the variation in the available spare capacity in each sequence as

integral numbers of units are added at the hydro-electric developments and

at thermal stations, These differences, when accumulated, represent the

benefit attributable to storage at Rankin Rapids as a result of accelerated de-

velopment of the downstream power potential, and amount to 9.22 million

dollars excluding the minor benefits in the years 1977 to 1980 inclusive, After

1980, there are no further benefits of this type.

The benefits attributable to storage at the Rankin Rapids develop-

ment under the various conditions which have previously been described, are

summarized in Table 75.

A strong transmission interconnection between The New Brunswick

Electric Power Corn-ission system and the utility systems in Maine, which

include the Rankin Rapids storage and power development, will result in

additional benefits in that the total hydro-electric energy generation on the

Saint John River can be increased by seasonal interchange of energy, The

amount of this increase may be derived from a comparison of Cases III(b)

and III(c), and Cases IV(b) and IV(c) as given in Tables 76 and 77. TABLE 75

SUMMARY OF TOTAL BENEFITS ATTRIBUTABLE TO THE RANKIN RAPIDS DEVELOPMENT

Passamaquoddy Tidal Power Project Passamaquoddy Tidal Power Project Not Constructed (Sequence III(b)) Constructed (Sequence IV(b)) Up to and In- Up to and In- Description of Benefit cluding 1980 After 1980 cluding 1980 After 1980

Millions of Millions of Millions of Millions of Dollar s Dollars Per Dollars Dollars Per Year Year

Energy benefit 13.25 1.1 13.20 1.1

Change of sequence benefit . 9. 13 9.22

Total benefit 22.38 1.1 ___c22.42 1.1 - - __I

Note: 1. Minor benefits in the years 1977 to 1980, inclusive, have been excluded.

2. The above benefits are obtained at the Beechwood and Mactaquac developments and the Grand Falls extension. Under other assumptions regarding interest rate and cost of fuel at thermal stations in New Brunswick, it may be economic to develop the Morrill site, in which case the benefits given in the above table will increase.

gi' 92 F 3. Benefits are determined by comparison with Case 11. ".C& per.,( - 163 -

TABLE 76

COMPARISON OF SYSTEM COSTS IN NEW BRUNSWICK AND NOVA SCOTIA FOR CASES III(b) AND III(c)

Case III(b) Case III(c) Case III( c)-III(b) Total Annual Total Annual Total Annual Annual Hydro Annual Hydro Annual Hydro Cost-106 Energy Gost-106 Energy Cost-106 Energy Year Dollars lo6 Kwh Dollars 106 Kwh Dollars lo6 Kwh

1966 21.86 1337.1 21.86 1337.1 0 0 1967 22.98 1357,7 22.98 1357.7 0 0 1968 24.84 1636.3 24.48 1744.4 -0.36 t108.1 1969 26.21 1646.7 25.88 1745.3 -0.33 t 98.6

1970 30.39 2488.1 29.91 2635.6 -0.48 4147.5 1971 33.54 2505.5 33. 14 2637.0 -0.40 t131.5 1972 35.01 2935.6 34.28 3164.8 -0.73 t229.2 1973 38.47 2958.6 37.81 3169.5 -0.66 t210.9 1974 42.26 3194.8 41. 67 3373.8 -0.59 t179.0 1975 46.08 3220.4 45.56 3383.1 -0.52 t162.7 1976 50.20 3316.9 49.79 3431.0 -0.41 t114.1 1977 55.92 3757.9 55.42 3911.5 -0.50 t153.6 1978 60.52 3777.1 60.06 3919.4 -0.46 t142.3 1979 66.91 3790.7 66.49 3927.1 -0.42 $136.4

1980 73.96 3800.9 73.56 3929.9 -0.40 t129.0

Total benefit *. . e.. . a -.. *. . . -. e -.. -6.26

Note: The annual system costs in Case III(c) do not include the annual charges for the transmission interconnection between The New Brunswick Electric Power Commission system and the utilities in Maine. , - 164 -

TABLE 77

COMPARISON OF SYSTEM COSTS IN NEW BRUNSWICK AND NOVA SCOTIA FOR CASES IV(b) AND IV(c)

Case IV(b) Case IV(c) Case IV( c)-IV(b) Total Annual Total Annual Total Annual Annual Hydro Annual Hydro Annual Hydro Cost-106 Energy Cost-106 Energy Cost-106 Energy Year Dollars 106Kwh Dollars lo6 Kwh Dollars lo6 Kwh

1966 21.86 1337.1 21.86 1337.1 0 0 1967 22.98 1357.7 22.98 1357.7 0 0 1968 24.84 1636.3 24.48 1744.4 -0.36 t108. 1 1969 26.21 1646.7 25.88 1745.3 -0.33 t 98.6

1970 30. 39 2487. 0 29.94 2621.5 -0.45 $134.5 197 1 33.54 2504.4 33.19 2619.2 -0.35 $114.8 1972 35.00 2937.4 34.27 3173.2 -0.73 $235. S 1973 38.46 2960.3 37.78 3180.9 -0.68 $220.6 1974 42.25 3198.2 41.69 3381.4 -0.56 t183.2 1975 46.07 3223.2 45.54 3393.4 -0.53 t170.2 1976 50.20 3316.2 49.80 3437.4 -0.40 t120.8 1977 55.92 3759.4 55.44 3912.1 -0.48 t152.7 1978 60.51 3778.5 60. 07 3918.9 -0.44 t140.4 1979 66.91 3792.3 66.46 3931.’5 -0.45 t139.2

1980 73.96 3802.9 73.64 3904.5 -0.32 t101.6

Total benefit . e ., e -.*. e e e e -.. -6.08

Note: See Table 76 in Case IV(c). - 165 -

The difference in annual charges between Cases III(b) and III(c), accumulated to the year 1980, amounts to $6.26 million, and the corresponding difference between Cases IV(b) and IV(c) is $6.08 million. There- after the benefits will be approximately $300, 000 annually. These figures represent gross benefits, as the system costs from which they are derived do not include annual charges on the transmission interconnection. The annual

charges for the necessary 138-kv transmission lines between the Beechwood development and Presque Isle in Maine are estimated at $213, 000. In Cases

III(c) and IV(c) the interconnection would be constructed in 1968, and the net benefits obtainable to .the year 1980 will amount to $3.70 million and $3.52 million, respectively. After 1980, the net benefit will be about $87, 000 per year.

If the benefits due to interconnection with Maine are added to those

obtainable at downstream plants from storage at Rankin Rapids, the total

' benefits which can be realized by the interconnected systems are as follows:

Cas e III( c) (Passamaquoddy Tidal Power Project not Constructed)

Benefits up to and including 1980 e e $26. 08 million

Annual benefits after 1980 e e -. e $ 1. 19 million

Case IV(c) (Passamaquoddy Tidal Power Project Constructed

Benefits up to and including 1980 e . e . . $25. 94 million Annual benefits after 1980 . a a *. -. $ 1.19 million - 166 -

Not included in these figures are the benefits resulting from the utilization of the transmission interconnection between The New Brunswick

Electric Power Commission system and the Nova Scotia utilities for the interchange of energy to give the maximum economy of power generation in both province s .

. The benefits given above represent the results of a study in which a variety of assumptions had to be made with regard to system growth, interest rates, and fuel costs. Nevertheless, they can be considered as illustrative

'of the magnitude of the benefits which can be obtained. - 167 -

TABLE 72 '

COMPARISON OF SYSTEM COSTS IN NEW BRUNSWICK AND NOVA SCOTIA FOR CASES 11, III(a) AND III(b)

Case Case III(a) Case III(b) Case III(a)-I1 Case III(b)-III(a) Firm II Peak Total Annual Total Annual Total Annual Total Annual Total Annual Demand Annual Hydro Annual Hydro Annual Hydro Annual Hydro Annual Hydro NB & NS Cost-106 Energy Cost-106 Energy Cost-106 Energy Gost-106 Energy Cost-106 Energy Year Mw Dollars lo6 Kwh Dollars lo6 Kwh Dollars lo6 Kwh Dollars lo6 Kwh Dollars lo6 Kwh (1) (2) (3) ( 4) (5) (6) (3)-(1) (4)-(2) (5)-(3) (6)-(4) 1966 798 23.87 1796.2 23.87 1796.2 '21 .,86 1337.1 0 0 -2.01 -459.1 1967 870 24.93 1832.2 24.93 1832.2 22.98 1357.7 0 0 -1.95 -474.5 1968 946 27.64 1854.8 26.92 2081.3 24.84 1636.3 -0.72 t226.5 -2.08 -445.0 1969 1033 28.89 2069.5 28.03 2338.3 26.21 1646.7 -0.86 t268.8 -1.82 -691.6 1970 1123 30.48 2211.8 29.53 2505.0 30.39 2488.1 -0.95 t293.2 t0.86 - 16.9 1971 1223 3k.06 2310.6 33.10 2613.3 33..54 2505.5 -0.96 t302.7 t0.44 -107.8 1972 1332 36.12 2389.2 35.15 2692.8 35.01 ,2935.6 -0.97 +303.6 -0.14 +242.8 1973 1452 39.58 2406.5 38.63 2710.1 38.47 2958.6 -0.95 f303.6 -0.16 +248.5 1974 1581 43.22 2419.7 42.27 2723.0 42.26 3194.8 -0.95 1.303.3 -0.01 t471.8 1975 1724 48.25 2543.8 47.34 2834.0 46.08 3220.4 -0.91 t290.2 -1.26 +386.4 1976 1879 52.44 2880.5 51.20 3275.5 50.20 331 6.9 -1.24 +395.0 -1.00 + 41.4 197711 2048 56.70 2899.6 55.47 3291.2 55.92 3757.9 -1.23 +391.6 +O. 45 1-466.7 1978 2230 63.21 2914.3 62.00 3303.0 60.52 3777.1 -1.21 t388.7 -1.48 +474.1 1979 2428 67.95 2925.0 66.75 3311.6 66.91 3790.7 -1.20 t386.6 +0.16 4479.1 1980 2643 72.14 3005.4 71.04 3358.8 73.96 3800.9 -1.10 4.353.4 -+2. 92 t442.1 Total benefit ...... -13.25 -9.13/2

/1 The Morrill development which is on line from the year 1977 on in Case III(b) is not common to the other cases. - Benefits in the years 1977 to 1980 inclusive have been excluded from this total.

TABLE 73

COMPARISON OF SYSTEM COSTS IN NEW BRUNSWICK AND NOVA SCOTIA FOR CASES II, IV(a) AND IV(b)

Firm Case I1 Case IV(a) Case IV(b) Case IV(a)-I1 Case IV(b)-IV(a) Peak Total Annual Total Annual Total Annual Total Annual Total Annual Demand Annual Hydro Annual Hydro Annual Hydro Annual Hydro Annual Hydro NB & NS Cost-106 Energy Cost-106 Energy Cost-106 Energy Cost-106 Energy Cost-106 E ergy Year Mw Dollars lo6 Kwh Dollars lo6 Kwh Dollars lo6 Kwh Dollars 106Kwh Dollars 102 Kwh (1) (2) (3) (4) (5) ( 6) (3)-(I) (4)-(2) ( 5)-(3) (6)-(d) 1966 798 23.87 1796.2 23.87 1796.2 21.86 1337.1 0 0 -2.01 -459.1 1967 870 24.93 1832.2 24.93 1832.2 22.98 1357.7 0 0 -1.95 -474.5 1968 946 27.64 1854.8 26.92 2081.3 24.84 1636.3 -0.72 +226.5 -2.08 -445.0 1969 1033 28.89 2069.5 28.03 2338.3 26.21 1646.7 -0.86 t268.8 -1.82 -691.6 1970 1123 30.48 2211.8 29.54 2501.7 30.39 2487.0 -0.94 t289.9 +0.85 - 14.7 1971 f223 34.06 2310.6 33.11 2612.1 33.54 2504.4 -0.95 t301.5 t0.43 -107.7 1972 1332 36.12 2389.2 35.16 2690.3 35.00 2937.4 -0.96 +301.1 -0.16 $247.1 1973 1452 39.58 2406.5 38.63 2707.9 38.46 2960.3 -0.95 t301.4 -0.17 t252.4 1974 1581 43.22 2419.7 42.28 2720.7 42.25 3198.2 -0.94 t301.0 -0.03 t477.5 1975 1724 48.25 2543.8 47.35 2831.2 46.07 3223.2 -0.90 +287.4 -1.28 t392.0 1976 1879 52.44 2880.5 51.20 3275.7 50.20 3316.6 -1.24 f395.2 -1.00 + 40.9 19774 2048 56.70 2899.6 55.47 3290.8 55.92 3759.4 -1.23 $391.2 +0.45 t468.6 1978 2230 63.21 2914.3 62.00 3302.7 60.51 3778.5 -1.21 t388.4 -1.49 t475.8 1979 2428 67.95 2925.0 66.75 3311.3 66.91 3792.3 -1.20 f386.3 $0.16 +481.0 1980 2643 72.14 3005.4 71.04 3359.2 73.96 3802.9 -1.10 +353.8 +2.92 +443.7 Totalbenefit ...... -13.20 -9.22!?

-11 - The Morrill development which is on line from the year 1977 on in Case IV(b) is not common to the other cases.

!? !? - Benefits in the years 1977 to 1980 inclusive have been excluded from this total. - 169 -

10 - EFFECTS ON OTHER WATER USES

10. 1 - Introduction

The Terms of Reference of the Saint John River Board require that consideration be given to the effects of future power developments on other water uses of the Saint John River basin. The valley with its magnifi- cent scenery and recreational facilities attracts visitors from a wide area and, for this reason alone, the river is of major important to the province.

However, it has many other values. Although ships no longer navigate the river above Fredericton, substantial amounts of pulpwood are driven each year from the upper reaches of the river to its mouth. It is a source of water supply, primarily for industry, but is used too freely for waste disposal. The river is fished both commercially and for sport, and the valley

supports several important species of wildlife.

In preceding sections of this report, it has been shown that the

power potential of the Saint John River in New Brunswick is substantial and that development of this potential will involve the construction of a dam and powerhouse at the Mactaquac site upstream from Fredericton, the installa-

tion of an additional unit at the existing Beechwood development, an exten-

sion to the Grand Falls development, and the construction of a dam and power-

house at the Morrill site between Beechwood and Grand Falls upstream from

the confluence of the Tobique and Saint John Rivers. - 170 -

At both the Mactaquac and Morrill sites, the river valley is com-

paratively narrow. The forebay of the Mactaquac development will have an

average width of approximately 2, 000 feet, a maximum depth of 130 feet,

and will extend for a distance of about 50 miles upstream to Woodstock. The

- forebay of the Morrill development will extend upstream to Grand Falls and

will have a maximum depth of about 70 feet.

The total volue of water which can be impounded at the Rankin

Rapids site in Maine is 8. 23 million acre-feet of which 2.8 million acre-

feet can be utilized as live storage with 35 feet drawdown. A lesser amount

can be impounded at the alternative Big Rapids site. However, in both cases,

the available live storage will. be sufficient to effect a substantial change in

the seasonal pattern of river flow. The freshet peaks in normal years will

be reduced although little protection will be afforded against the estimated

maximum possible flood on the river. Low flows will be increased with

possible beneficial results in relation to a number of water uses in addition

to power generation.

The effects of these power developments and impoundments on

other water uses should be considered in the light of forward trends. As

urban congestion increases and as more leisure time becomes availabl6

there will be an ever increasing demand for adequate recreational facilities

where people may relax and enjoy all of the amenities which nature provides.

This will only be possible in the Saint John River valley if measures are

taken to improve and maintain water quality. - 171 -

10.2 - Water Quality .

The dissolved oxygen content and the amount of suspended solids in

river water are factors which have a major influence on many water uses. For

example, fish cannot live in water with a dissolved oxygen content below a certain

value. Suspended solids will settle in the forebays-of power developments and on

stream beds, creating undesirable conditions for recreation, fish spawning and

other water uses.

Pollution of a river will both reduce the dissolved oxygen content

and increase the solids in suspension, and will be harmful to fish life, recreation,

andwater supply. The effects of new power developments on the Saint John

River on other water uses will vary therefore, depending on future measures

adopted to .control pollution, 'and the two .problems anus$ be considered to-

gether o

The New Brunswick Water Authority was asked by the Board for an

. opinion on the effects of power developments on water supply and pollution of the

Saint John River. The statement received from this Authority is given verbatim

in Section A9 of the Appendix.

Five surveys in recent years have established something of a base

line for judgment of present pollu$ion. The New England-New York Inter-Agency

Committee study reported the conditions in considerable detail on the United

States tributaries and along the upper and international reaches of the Saint John

River in Maine, with particular reference to heavy pollution by the pulp mill

at Edmundston. The New Brunswick Water Authority Preliminary Survey of - 172 -

Pollution in the 'Saint John River Watershed in 1958, reported the results of chemical and physical tests of single water samples at numerous points along the course of the rivkr and its tributaries in the province during the summer season. The Authority's 1959 survey based on weekly samples from several stations during a twelve-month period in 1958/1959, gave some idea of seasonal variations iq water quality. The New Brunswick Water Authority field survey report of 1959 covered intensive sampling and testing on the upper Saint

John River, along the Kennebecasis River watershed, and in the Saint John

Harbour, The Fisheries Research Board of Canada mqde a field study of water samples and riverbed fauna in 1959. During the low water period in midsummer 1960, the Department of National Health and Welfare, Canada, in co-operation with the New Brunswick Water Authority, is undertaking a more intensive field survey of water quality from'a point 50 miles above Edrnundston to the mouth of the river, including sarnples fromthe major tributaries,

The prospect is that various agencies will be conducting water surveys periodically in future to trace the changing conditions and to compare the results after more power dams are constructed. In particular, winter conditions need to be studied so that corrective measures can be taken, if required, to ensure that the dissolved oxygen content does not fall below the critical level for fish life.

In the Saint John River above the Rankin Rapids site in Maine the quality of the water is high, Construction of a storage and power development - 173 -

at this site will create a reservoir some 60 miles long with a maximum depth of over 300 feet. This reservoir will generally improve the quality of impounded water except that the dissolved oxygen content may be somewhat reduced.

From the Rankin Rapids site to Ehundston, the river flows in a series of shallow rapids and ponds, and these natural facilities for self- purification and replacement of oxygen will remain after the Rankin Rapids development is constructed. Indications are that although water released from

Rankin Rapids may at times be somewhat deficient in oxygen, the water should continue to be saturated, or nearly saturated with oxygen before reaching

Edmund st on.

The Saint John River from Edmundston to Grand Falls is a striking example of a reach which is already impounded and grossly polluted with no hope of improvement until at least the heaviest load of pulp mill waste is treated for recovery of organic content. The effects of this pollution are felt far downstream. The installation of additional units at the Grand Falls plant for peak load operation, may have a minor detrimental effect in minimizing spillage through the sluiceways during periods of heavy flow. The dissolved oxygen . levels from Edmundston to the Grand Falls dam are reduced to the 1-ppm range during the low flows and high temperature conditions of August. Pollu- tion by industrial waste is the problem in this reach.

The reach from Grand Falls to the Morrill site provides aeration which will be lost following the construction of the power development at the - 174 -

latter site. The introduction of air at the turbines of the proposed Morrill development will help in restoring dissolved oxygen to the water. However, upstream pollution must be reduced if the required water quality is to be assured in the Beechwood headpond.

The reach from Beechwood to Woodstock is wide and shallow, and is ideal for re-aeration. It will not be affected by any of the proposed power developments and the'maintenance of minimurn flows will protect the spawning, nursery, and angling areas. Measurements in June 1958 at the

Woodstock bridge, showed a dissolved oxygen content between 8.5 and 9.7 ppm, or over 85 per cent saturation.

From Woodstock t.o Mactaquac, the river valley is comparatively thinly populated and local pollution is not yet a serious problem. Construction of a dam at the Mactaquac site will reduce biochemical oxygen demand, coliform concentration, turbidity and colour of the water downstream. On the other hand, the loss of aeration will reduce the dissolved oxygen content and create a problem needing further study.

The reach from Fredericton to the Bay of Fundy is wide, navigable and subject,to tidal action. Brackish water extends from the Reversing Falls to about the middle of this reach. The drainage area tributary to this reach of the river is about 27 per cent of the total drainage area of the river at its mouth and includes such tributaries as the Nashwaak, Oromocto, Jemseg and

Kennebecasis Rivers. In general, the power dams should have little effect - 175 -

on this reach, The problems of pollution call for action to improve the water quality for water supply, bathing, boating and aesthetic values

From the preceding discussion which is amplified in the report

submitted by the New Brunswick Water Authority, it is apparent that pollution

should be controlled at the point of origin. The sources of present pollution are the pulp and paper mills at Edmundston, New Brunswick, and Madawaska,

Maine, the numerous potato starch factories on the river and its tributaries

above Woodstock, several food processing plants and, of course, the many municipal sewage outlets. By pollution control at source, the Saint John

River can be kept clean for boating, fishing, wildlife and all other factors

and activities which attract residents and tourists alike.

10.3 - Recreation

The artificial lakes created by the construction of power dams on

the Saint John River will have several unique features which will enhance

their value for recreational purposes. The water levels of the forebays at

Mactaquac and Morrill will not fluctuate more than say five feet compared

with a natural seasonal fluctuation in the river of about 25 feet. They will

be ideally situated, as the Trans-Canada Highway follows the Saht 'John

River valley and will pass each of the existing and potential developments in

New Brunswick, The use of recreational facilities is subject to seasonal

fluctuation, and therefcjre depends on part-time labour for maintenance and

operation. The location of recreational areas in the populated valley of the

Saint John River is therefore an advantage. - 176 -

Although The New Brunswick Electric Power Commission is primarily interested in the generation of electric power, it has accepted the principle of multipurpose usage of existing and newly created ponds and storage areas. The Commission has already given considerable study to possible uses of the headponds at Beechwood and Tobique Narrows for recreational purposes. The considered conclusions as to policy of the Power

Commission in this connection were set out in a letter from the Chairman of the Commission to the Board as follows:

"(1) - The Commission intends to make information available to individuals, clubs, municipalities, county authorities, and others, regarding sites which appear to be suited for various recreational needs, such as beach bathing, possible launching sites for small craft, boat docking sites, etc. Such information, particularly if it is supplied before the construction of new power dams is completed, will allow site improvements to be made conveniently before the final flooding occurs. Such improvements could include the removal of stumps, sods, and other undesired material, the preparation of beaches, ramps, etc.

"(2) - The Power Commission does not intend to finance and operate recreational facilities, and its interest in entertaining the public need will most likely be confined to the operation of guest houses with guides, information, and lavatory facilities at each of its major power sites.

"(3) - The Commission intends to make land available to interested parties on a rental or leasing basis. At some of the new reservoirs minimum purchase of land above the controlled water levels is planned by the Commission. It follows that many of the recreational facilities will be located largely on privately- owned land and to the owners and operators of these facilities, the Commission intends to afford access - 177 .-

arrangemerrts to the reservoirs over the Commission- owned margin, except at such points where interference with power production would result.

"These policies of the Commission with respect to the multipurpose uses of existing and proposed reservoirs along the Saint John River, should have a stimulating effect on the activities of other agencies, both private and public, which have the welfare of the area at heart. I'

Among the many types of developments which have recreation appeal to the public are the followip-g:

Public parks and wildlife refuges.

Bathing beaches carefully located on shelving gravel or sandy slopes.

Boat launching sites, read-ily accessible frozm highwaysg where trailer-borne boats may be launched and where cars and trailers can be parked.,

Boathouse sites for clubs and commercial establish- ments where sailboats, outboard motor boats, row- boats, canoes, and the like may be hired.

Marina sites where gas, oil, lunches, tackle, and bait may be secured.

Camping and tenting sites, operated by tourist author itie s or private individuals.

Cottages and cabins for private use as well as for

seasonal renting e

Motel sites,

Restaur ants.

With the passing of time, these facilities, easily accessible and located in the valley of the Saint John River, should attract large numbers of visitors and provide a valuable source of revenue for the province. - 178 -

10.4 - Fish

The Saint John River and its tributaries support anadromous and resident species of fish which are caught both commercially and for sport.

A great deal of information is available concerning the effects of dams on the migration, spawning and rearing of fish, but experience has shown that each dam presents its own unique problems. While some generalities are possible, comprehensive biological studies of the species of fish involved and a detailed analysis of the operation of the developments are required before recommendations for protective facilities and measures can be formulated.

A statement on these subjects by the Department of Fisheries,

Canada, is included in Section A9 of the Appendix. The Department reviewed the life history, known distribution, and degree of exploitation of the various species of fish in the Saint John River and made a preliminary analysis of the problem of fish passage at the proposed developments. Fish species that could be affected are:

Atlantic Salmon Speckled Trout Sea Sturgeon Black Bass Shad Gaspereau or Alewife Striped Bass Pike (Chain Pickerel)

As a result of this preliminary review, it is the opinion of the

Department of Fisheries that resident species of fish are likely to at least maintain themselves, but runs of anadromous fish may be reduced. The

Department estimates that the studies which will be required to determine the effects of these power developments on fish will take a minimum of two years to complete. - 179 -

From the preliminary analysis of the problem of fish passage at the proposed developments, the Department of Fisheries has indicated in a general way the temporary and permanent facilities required at the Mactaquac

site for the passage of Atlantic salmon. In this connection, it is stated that a dissolved oxygen concerkration of 5 ppm is a minimum required for salmon.

However, the species normally exists in water which is at the saturation

level and some stress would be expected as a result of prolonged exposure to concentrations below saturation.

A great deal of experience has been gained in attempts to deal with the fisheries problems and, while such attempts have not always been successful, there are notable examples where the value of rivers as fish

resources has increased considerably after power development.

Problems similar to those which will arise on the Saint John

River with respect to the fisheries resource are by no means unique, and have been studied in many other areas where available water power has been

utilized, notably in Scotland, Ireland, Sweden, and the United States. It is

to be expected that further research will greatly improve the chances of

dealing successfully with the problems involved. With respect to the Saint

John River, some problems for such research are:

(‘1) - Migration of fish life upstream with the help of fish ladders and truck transportation, and downstream through turbines and sluices.

(2) - New spawning beds in the tributaries and bays below the proposed Mactaquac dam, and artificial facilities such as fish hatcheries above and below Mactaquac. - 180 -

(3) - The stocking of power and storage reservoirs with selected species of resident fish.

(4) - The estimation of minimum flows in the different stretches of the river at ,different times of year needed to preserve fish life.

(5) - Special facilities for the control of dissolved oxygen in different reservoirs and from different depths to ensure optimum conditions for fish life.

10 5 - Wildlife

While many of the flooded areas of the Mactaquac and Morrill developments have been cleared and cultivated for many years, there are other areas which form an ideal habitat for various species of wildlife.

Arnong the wildlife found in the valley of the Saint John River are terrestrial game species such as pheasant and deer, and several species of fur bearing animals and waterfowl. The changes in environmental conditions caused by the change in water levels and river flows will affect these species in different ways, and opinions on these effects were obtained from the Northeastern Wildlife Station at the University of New Brunswick and from the Canadian Wildlife Service, Department of Northern Affairs and

National Resources. The statements received are reproduced verbatim in

Section A9 of the Appendix.

Pheasant inhabit the low flat areas along the shores of the river and the river islands and provide sport each season for a limited number of hunters. As shores along the proposed reservoirs will be less suitable habitat for the pheasant, the pheasant population will be adversely affected - 181 -

for some time after the reservoirs are constructed. However, it may well be that, in time, the pheasant population can be restored at least partially,

Muskrat, mink, otter, and beaver are.found in some areas along the river, but the region which will be flooded yields very little fur at the present time, The establishment of relatively stable water levels in the new reservoirs should benefit the mink and especially the muskrat.

Although some islands are used by waterfowl as a resting area in late summer and during fall migration, the river in its present condition is .. not suitable for waterfowl because of the swift current. The creation of larger water areas with less current may be expected to result in a new and very much better waterfowl habitat. Initially, feed will be scarce, as there will be few shallow areas where food plants can become established, However, it may be possibie to develop feeding areas in some of the surrounding country; for instance, in the valleys of the Pokiok and Shogomoc Rivers, in the large swampy areas north of Queensbury, and-in the upper reaches of Gardens Creek,

Ducks will nest on the banks of the reservoir and in the surrounding country, and will congregate on the reservoirs at the end of the summer.

Migrant waterfowl, including ducks and Canada g.eeses will use the reservoirs as these will be the first large bodies of water ta be found after crossing the large forested areas of northern New Bruswick.

At the present time, drastic fluctuations in water levels in the estuary of the river below Fredericton during the nesting season seriously L 182 -

curtail its use by both ducks and muskrats, Development of the river for the purpose of power generation might result in an additional benefit to waterfowl in that the water levels may be subject to less fluctuation than heretofore,

Summarizing, it may be said that some loss will undoubtedly occur in the pheasant population, but that this loss will be offset by a gain in ducks, both in the reservoirs and in the river estuary. The effect of the reservoirs on other terrestrial wildlife will probably be negligible.

10.6 - Navigation

Navigation of the Saint John River by ships reached its peak around the middle of the nineteenth century and with the advent of the railroads in New Brunswick, navigation gradually declined until, after 1900, only limited freight service was available between Fredericton and Saint John. Preseb use of the river is lisnited to the occasional transportation of oil in small tankers between Saint John and Fredericton. In its present state, the Saint

John River can be considered as navigable only in this reach. Charts from the Hydrographic Service, Department of Mines and Technical Surveys, dated

1933, show a minimum water depth downstream from Fredericton of only eight feet in places in the low flow summer months; navigation in this reach could be maintained or improved by dredging. Upstream from Fredericton, the shallow depth of the river at low summer flows precludes its regular use by large craft, and measures to create and maintain a navigation channel would appear to be uneconomic, - 183 -

10.7 - Log Driving

Lumber and pulp, the basic industries in the Saint John River basin, use the river system for log transport. While the modern trend favours transportation of the logs by trucking, particularly where sinkage losses are considerable and hardwood species are used, water transport still remains an important means for movement of the vast quantities of timber from the upstream forests to the downstream mills. In this respect, the harmful effects of falling bark, sunken logs, and dissolved organic matter should not be overlooked as a source of river pollution.

Further storage and power development would affect the lumbering industry. Successful log driving is dependent on the stage of the river, and optimum conditions exist for log driving approximately two weeks after the occurrence of the spring freshet. However, due to the absence of storage basins for log driving, rapid fluctuations in the flow of the river sometimes

occur, and quite often the period of optimum flow does not last long enough' for successful co-rnpletion of the drive. As a consequenceo logs may be

stranded on bars and islands and their recovery is time consuming and ex- pensive.

The construction of power dams along the main stem of the river will necessitate changes in the methods used for log driving. However, the

*operationwill become less dependent on the river flows, and most of the ex-

penditures now required to salvage stranded timber will be eliminated. - 184 -

Making the most beneficial use of the river clearly requires co-ordination of log driving interests and power interest.

10.8 - Summary

The development of storage on the upper Saint John River will change the flow pattern of the river in New Brunswick in that the volume of spring runoff will be reduced and low flows increased. Additional changes in river characteristics will be caused by the construction of additional power develspmects on the lower Saint John River. If pollution of the river is controlled at source, and if advantage is taken of the opportunities which exist for multipurpose use of the proposed reservoirsp the effect of these changes on the use of the river for purposes other than power generation can be beneficial. Some conflicts exist among the different interests sharing the use of river water, but the development of the Saint John River should be considered in the light of forward trends. It seems timely therefore that a start be made to resolve conflicts of interest.

The changes in river characteristics may be detrimental to some species of fish, but it is probable that other species will be encouraged, so that the value of the river and its tribEtaries for angling could be increased in the future. There will be a change in habitat for wildlife. For instance, the pheasant populatiox in the flooded areas of the power developments will be adversely affected for some time after the reservoirs are constructed.

However, this temporary loss will be offset by an increase in other game - 185 -

species, particularly ducks, which will benefit greatly from the smaller fluctuations of the water levels both in the reservoirs and in the river estuary.

In many areas in Canada and the United States, urban congestion has increased to a point where thousands are looking for open spaces during frequent holidays and after retirement. If the possibilities for the creation of recreational facilities in the valley of the Saint John River are utilized to the full, New Brunswick seems likely to attract visitors from these areas on a scale never imagined in the past. With foresight and wise planning the

Saint John River valley could become a recreational area ranking among the best in North America, and a growing economic asset to the Province of New

Brunswick. - 186 -

11 - FINDINGS

The findings set out hereunder are based upon a number of

assumptions which have been detailed in the report. The more important

of these assumptions are restated as follows:

(a) - An interest rate of 5.5 per cent has been assumed for all of the

studies of power systems in New Brunswick. This figure approximates the maximum yield to maturity for provincial bonds issued in New Brunswick

for the construction of power facilities since 1948. The minimum yield

since 1948 was 3.5 per cent, indicating that the actual interest rates in the

future could well be lower than was assumed in the study.

(b) - It has been assumed that the cost of fuel at thermal-electric

generating stations will be equal to the cost of Bunker C oil as of January

1959, namely, 35 cents per million Btu and will remain constant in the

future

system of The New Brunswick Electric Power Commission will grow at the

rate of 9.4 per cent per year and that the load factor will remain substan-

tially constant.

As a result of its studies to determine the probable pattern of

future power development in the province of New Brunswick without addi-

tional storage on the Saint John River and its tributaries, the Board, within

the framework of these assumptions, finds that: - 187 -

(1) - The power potential of the Saint John River in New Brunswick is ,..._- *” economic if developed in conjunctionwith thermal power, even under the con- ?z$w,s ,. - -?.-I->_ L%--.. dition of there being no -,=-’ energy&+erchange with Nova,Scotia and no develop,- ment of storage at Rankin Rapids. ,..< 1. -L< ..- (2) - The development of this power potential can be accelerated if energy is interchanged between the .systems of The New Brunswick Electric

Power Commission and the Nova Scotia utilities to give a maximum of economy in operation.

(3) - A total net generating capability of 643 megawatts can be developed .* , -, at the Mactaquac site on the Saint John River and by extension of the existing --“...I ~ ” Grand Falls development. The average benefit-cost ratio is greater than -v.z.,i unity when compared with equivalent thermal-electric generation.

- Using the assumptions described above, the economy of theMorril1 (4) -”,... ,. development with a net generating capability of 98 megawatts is practically *--*-<*--* the sqme as that of equivalent therma1:plectric._?.. generation in New Brunswick. __._I-,-. ~

(5) - It will be economic.. .- to add a third unit*- at the existing Beechwood development as planned, giving a t,ota&,nst generating capability of appr oxi- mately megawatts. Further capacity additions at the development will not be economic.

As a result of its studies to determine the effects of upstream

storage on existing and future power developments on the Saint John River,

in New Brunswick, ’the Board finds that: - 188 -

(6) - The sBSgs&s,which can be developed aLsit.e.s .on tributaries, of the

Saint John River are not*L >..:.. large,I but would have a in accelerating

development of the power potential of the SaintJ ohn River ift~e~-~i~-~-o”~~nergy

interchange between the utilities of New Brunswick and Nova Scotia. The de- ----“sa---.. ., -._ _--_ velopment of some of these storages will p_=vide greater flexibility in opera-

tion of The New Brunswick Electric Power Commission system if no major upstream-- storage site on the Saint John River is developed. (7) - If the Macauac development and the Graqd.-F~$lsz~w~~nsionare

constructed in accordance with the sequences which were studied, the fotalI-... . .-c downstream benefits-- attributable to the Rankin Rapids development with a 4 i, 9” live storage of 2, 800, 000,.‘.. acre-feet are as given in Table,7,5,,, p

(8) - If lesser amounts of live storage are developedat theRankinRapids .- . ~...,... .. 1.

site, or if the Big Rapids and Lincoln School developments are constructed,

benefits attributable to upstream storage in Maine as given in Ta$Jl,7,5_willa

be reduced. _cII

(9) - When the Morrill-^‘a site is developed, the ba2fits given in Table 75

will inEase.

(10) - Based on the studies and the trends indicated by these studies, 1 1 the devfe_&ment and -ope-ration,of upstream storage on the Saint John River i i will not change the ultimate capacities .at+.dev.elopments downstream.

-I--..._ ~

With respect to the uses of the Saint John River for purposes

other than power generation, the Board finds that: . .. - 189 -

(11) - The construction of additional power dams along the main stem

of the river will cause changes in water quality and use. By controlling

pollution at source and by taking advantage of the opportunities for multi-

pur po s e development , the e f f e ~ts.~.o--~~~~--po~~erdevelopment s on othe r wat e r

uses .c-an be----*--~-.*--. beneficial in . -..mog&respects. . Special measures will have to be

taken to counteract any adverse effects arising from certain changes brought

about by power developments. Such steps would enhance the value of the Saint

John River as an asset to the Province of New Brunswick.

100

0 OCT. MOV. DEC. JAN. FER MAR. APR. MAY JUNE JULY AUG. SEPT MONTHS

LEGEND NATURAL FLOW AT THE BEECHWOOD DE V E LOP MENT SAINT JOHN RIVER BOARD MODIFYING EFFECT OF EXISTING STORAGES SAINT JOHN RIVER m\v MODIFYING EFFECT OF RANKIN RAP1 DS TYPICAL MODIFYING EFFECT OF RANKIN RAPID: STORAGE AND EXISTING STORAGES

JUNE ,1960 PLATE 2 PREPARED BY H.G. ACRES a COMPANY, LIMITED. YEARS

NOTE FOR THE PURPOSES OF THIS STUDY THE NEW BRUNSWICK INTERNATIONAL PAPER AN0 FRASER COMPANIES LOADS HAVE BEEN ASSUMED BY THE SA111 JOHN 7;;~s;;$;mN,:!L e~sT:~A,~owl:~~R~A,~~y:5,p" MEOAWATTS. THIS RESULTS IN

SAINT JOHN RIVER BOA

LOAD GROWTH OF NEW BRUNSWICF

ELECTRIC POWER COMMISSION SYSTI

PREPARED BY H.O. ACRES B COMPANY, LIMITED. JUNE , 1960 PLATE _-

IO0 n z a z 90 W n 5 80 w 0. bb 70 0 k- z w 6o 0 E W 50 av) z0 40 Q I W e 30 er w 253 20 z 5 10 LL

0 0 10 20 30 40 50 60 70 80 90 100 PERCENT TIME

COORDINATES OF STRAIGHT LINE APPROXIMATION USED IN SYSTEM STUDIES PER CENTAG E PERCENT OF PEAK DEMAND TIME 0 100 SAINT JOHN RIVER BOARD 26 10 0 38 94 65 60 MONTHLY LOAD DURATION CURVE 79 37 85 1 15 NEW BRUNSWICK ELECTRIC 92 5 100 10 POWER COMMISSION SYSTEM

JUNE , 1960 PLATE PREPARED BY H.G. ACRES a COMPANY, LIMITED. 4 5-0

4.8

4-7

4.6

4.5

4.4

4-3

4.2

4. I

4.0 0 IO 20 30 40 50 60 70 80 90 100

POWER OUTPUT FROM THERMAL STATIONS - MEGAWATTS

NOTE VARl ABLE ANNUAL CHARGES INCLUDE SAINT JOHN RIVER BOARC INCREMENTAL FUEL COSTS AND THE VARIABLE COMPONENT OF OPERATION AND MAINTENANCE COSTS. VARIABLE ANNUAL CHARGES FOR EXISTING THERMAL-ELECTRIC STATIONS NEW BRUMSWICK ELECTRIC POWER COMMISSION SYSTEM

PREPARED BY H.G. ACRES R COMPANY, LIMITED. JUNE ,1960 PLATE 5 100 0 % 4 5 W Q 80 Q* W L IL 70 0 I- 60 0 wM 50 io 5 40 4z w P 30 or: W g 20 P 5 5 10 lL

0 0 10 20 30 40 50 60 70 80 90 100 PERCENT TIME

COORDINATES OF STRAIGHT Ll NE APPROXIMATION USED IN SYSTEM STUDIES PERCENTAGE PERCENT OF PEAK DEMAND TIME 0 100 SAINT JOHN RIVER BOARD 31 IO 0 36 95.5 40 81.5 70 50 ASSUMED MONTHLY LOAD DURATION CURVE 82 23.5 90 4 NOVA SCOTIA INTERCONNECTED LOAD IO 0 0

JUNE, I960 PLATE6 PREPARED BY H.G. ACRES a COMPANY, LIMITED.

3500 - 3000 - cn I I-z 2500 - 5 cn LL. u I w 2000 - (3 a 0 I- v) w 1500 - 3 -I LL. 0 w 1000 - 5 3 -I 0>

500

0 APRIL MONTHS

NOTE THE ABOVE RULE CURVE IS FOR SAINT JOHN RIVER BOARD EXISTING STORAGE ON THE TOBIPUE RIVER AND IS TYPICAL OF THE PREDETERMINED RULE CURVES USED TYPICAL RULE CURVE FOR CONTROL OF SECONDARY STORAGE. FOR CONTROL OF STORAGES

IUNE ,1960 PLATE I2 PREPARED BY H.G. ACRES a COMPANY, LIMITED. W B f

m D P 0 -ll rs f PW E

%= FI

I ul ulQ I I

n I =!z a

ffl g0 e 8 --1 t I W I W P I z t YI 2 a P I 0 I e E P p; N --1 = e z0 c es z I

I 1 I -" OD 0::

0 e

Y9 s E J

0, n9

3 0 L f "3 - - c c (I) z m -D - z W -i tn 0 c 0 I z -n < rn a -u m r D 0 -4 m D D".. - ;o cn W - - SCHEMATIC INDEX CASE I

------__-

NEW BRUNSWICK GENERATION ADDITIONAL STORAGE ON THE ST. JOHN RIVER

MEGhWATTS

1960 227

1961 246

1962 260

1963 291

1964 317

1965 344 t

1966 373

Y 0 19 67 E 406 I""NO. 111 102 a.s 1968 m 440

Y3 ! 2 i 1969 480 I z ! 0 ! 1970 9 I20 wI >

Y 565 !I 1971 I"""0. I.. nu" Io. 9s. I""10.11, I"" W.M. I""%a 141 w I + 7------T-----l 1972 $ 614 2 4 1973 r 667 i

1974 724

1975 788

1976 655

1977 930

1978 1010 GRAND LAKE Nrl SAINT JOHN RIVER BOARD

1979 1095 NOTE SEQUENCES OF DEVELOPMENT THE INDEX REFERS TO THE SYSTEM OF THE 1980 1190 NEW BRUHSWISK ELECTRIC POWER COUUISSION. SCHEMATIC INDEX-CASE I

PLATE 16 I 'PIRED BY H.G. ACRES B COMPANY, LIMITED. JUNE , 1960 H ZZ

- cn -D z -1

c 0 I z -so < m so

m 0 D so -0 FIRM ANNULL PEAK DEMAND IN NEW BRUNSWICK

I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I --_ . 7---

FIRM ANNUAL PEAK DEMAND IN NOVA SCOTID 5;:;;:: 100

W n

LL 70 0 I=- 60 0 K W 50

0 0 IO 20 30 40 50 60 70 80 90 100 PERCENT TIME

COORDINATES OF STRAIGHT LINE APPROXIMATION USED IN SYSTEM STUDIES PERCENTAGE PERCENT OF PEAK DEMAND TIME 0 100 SAINT JOHN RIVER BOARD 37 100 43 95 4 6.5 90 56 67 ASSUMED MONTHLY LOAD DURATION CURVE 79 46 94 6 FOR A UTILITY IN MAINE 100 0

PREPARED ay H.G. ACRES a COMPANY, LIMITED. JUNE, 1960 PLATE 19

I _.

0 50 IO0 150 200 25 0 300

THERMAL INSVALLATION IN MEGAWATTS

NOTE CURVE A - POTENTIAL AVERAGE ANNUAL AT SITE GENERATION SAINT JOHN RIVER BOARD CURVE B- FIRM ENERGY OUTPUT

RANKIN RAPIDS DEVELOPMENT POTENTIAL AVERAGE AT-SITE ENERGY CASES III (A) AND IlI (B)

JUNE, I960 PLATE 20 PREPARED BY H.G. ACRES a COMPANY, LIMITED. I2 31Vld 0961 '3Nnl'

(W) HI 3SW3 - US03 aNW NOILVU3N39

LN3Nd013h3a A0 S33N3fl83S atlvo~~3,118 NH'O~LNIVS V1103S VAON (INV 831MSNflME M3N NI 1503 A9M3N3 WMld 1VPNNV 3OVM3AV

CUV3.4

VIlO3S VAON (INV HDIMSNllME M3N NI S3BMVH3 NOISSIASNVLU (INV NOllVY3N38 1VllNNV

51112.4

V1103S WON (INV 831MSNllME M3N NI NOllVM3N30 J.3M3N3 YlMU 1VnNNV

SUV1A VI1035 VAON ONV X3Ih\SNflBO M3N NI NOIlVB3N3L) AOB3N3 VlYl3 1VflNNV

lull*

I '(1311ylll 'ANVdYl03 B S383V 'O'H 18 (13YVd3Yd X31fiSNIlYil M3N NI lNPWd013A3(1 IO 33N3IlD3S PZ 31VJd 0961'3Nnf I

Q11035 QAON ONV X31MSNnYB M3N NI NOUVM3N30 hDU3N3 WYU 1QIlNNV

IY.3.I Ill l!I I Ill I I I II IIil I I IiI I I I = II:I I Ill I I I 0 III I I I I I I I I FLOWS IN CUBIC FEET PER SECOND OOOOD 1:l FLOWS IN CUBIC FEET PER SECOND 300

THERMAL INSTALLATION IN MEGAWATTS

NOTE CURVE A - POTENTIAL AVERAGE ANNUAL AT SITE GENERATION SAINT JOHN RIVER BOARD CURVE 8 - FIRM ENERGY OUTPUT

RANKIN RAPIDS DEVELOPMENT POTENTIAL AVERAGE AT-SITE ENERGY CASES (A) AND ISL (B)

JUNE, 1960 PLATE 26 PREPARED BY H.G. ACRES a COMPANY, LIMITED. 0

oNA"D----- NN FLOWS IN CUBIC FEET PER SECOND 000 00000000 FLOWS IN CUBIC FEET PER SECOND

1 tUV31

V1103S VAON ONV H31MSNIl1E h\3N NI N011W3N3O hOU3N3 Wklll 1VIlNNV

111.11h - .I ,E1

m zc 3 x

- c c 0 z D m - - z (0 -1 m 0 L 0 I z -a < m a

a m r D 0 -I m D 23 N UJ 0 - - f

- c c z m - W m 0

D I- P -I m u 0