REGULATION OF GREAT LAKES WATER LEVELS APPENDIX F POWER BY THE REPORT TO THE INTERNATIONAL JOINT COMMISSION INTERNATIONAL GREAT LAKES LEVELS BOARD

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2 REGULATION OF GREAT LAKES WATER LEVELS APPENDIX F POWER REPORT TO THE INTERNATIONAL JOINT COMMISSION BY THE INTERNATIONAL GREAT LAKES LEVELS BOARD (UNDER THE REFERENCE OF OCTOBER 7,1974) DECEMBER 7,1973

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4 SYNOPSIS This appendix presents the results of the studies of the effects of regulation on hydroelectric power generation. These studies were undertaken by the International Great Lakes Levels Board which was established by the International Joint Commission on December 2, The purpose of the studies was to determine the economic effect of changes in levels and flows as a result of regulation on the generation of hydroelectric power on the connecting channels of the Great Lakes and on the St. Lawrence River. The methodologies used in evaluating the effect of the various regulation plans indicate the benefits or losses resulting from changes in levels and flows to the hydroelectric power generation for energy and capacity in all systems where these types of electric power could be considered. Because the hydroelectric installations of Hydro Quebec are restricted at the time of maximum system load by ice conditions, no evaluation of capacity was made. The methods used in the evaluations were those used in current economic studies by the power entities involved. The conditions expected in the interconnected New York State and Ontario HydrQ systems in 1985 were used in the analysis. The regulation plans designated SO-91, SEO-33, SEO-42P, SMHO- 11 and SMHEO-38 were selected by the International Great Lakes Levels Board and evaluated with respect to the basis-of-comparison conditions. These evaluations are provided in this appendix. The results of the entire studies as well as the findings and conclusions are provided in the International Great Lakes Levels Board's report, Regulation of Great Lakes Water Levels. F- i

5 TABLE OF CONTENTS REGULATION OF GREAT LAKES WATER LEVELS APPENDIX F POWER Page SYNOPSIS TABLE OF CONTENTS LIST OF TABLES LIST OF FIGURES LIST OF APPENDICES F-i F-ii F-vi F-ix F-xi Section 1 INTRODUCTION 1.1General 1.2Organization 1.3 Procedure of Power Study F- 1 F- 1 F- 1 Section 2 ST. MARYS RIVER POWER PLANTS 2.1 General Description Canadian Power Plants United States Plants 2.2Assumptions 2.2.1General Canadian Plants United States Plants 2.3 Methodology for Determining Capacity and Energy Output Canadian Plants United States Plants F- 3 F- 3 F- 3 F-5 F- 5 F-5 F-6 F-6 F-6 F- 14 F-ii

6 TABLE OF CONTENTS (cont'd) Page Section 3 NIAGARA RIVER POWER PLANTS 3.1 General Description Canadian Plants United States Plants F- 16 F- 16 F Methodology for Determining Energy and Peak Capacity Output 3.2.1Assumptions Basic Data Derived Data Total Energy Output Computations for Canadian Plants Total Energy Output Computations for United States Plants Peak Capacity Output Computations for Canadian Plants Peak Capacity Output Computations for United States Plants F-19 F- 19 F- 19 F- 2 F- 22 F- 29 F-46 F- 5 Section 4 MOSES-SAUNDERS (ST. LAWRENCE) POWER PLANTS 4.1 F Methodology for Determining Energy and Peak Capacity F-53 c Assumptions F-53 F-54 rived F Determination of Capacity of St.LawrencePlants F Determination of Total Daytime and Total Nighttime F-61 Energy Outputs Section 5 BEAUHARNOIS-CEDARS (ST. LAWRENCE) POWER PLANTS 5.1 F Methodology for Determining Energy Output at Beauharnois- F-64 Cedars Power Plants Assumptions F-64 c F-64 rived F-64 Computation F-69 Output of Power F-iii

7 TABLE OF CONTENTS (cont'd) Page Section 6 DETERMINATION OF UNIT ENERGY AND CAPACITY VALUES Values Capacity 6.1 and Energy F- 73 gan Upper 6.2 F- 73 System 6.3 Ontario F- 74 Load East Ontario F- 74 stem East Ontario Determination and Evaluation of System Peak Increments F Evaluation of System Energy Increments F- 77 York 6.4 New F Determination of the Value of Energy in New York F Determination of the Value of Peak Capacity in F- 79 New York 6.5 Quebec System 6.5.1General Determination of Capacity and Energy Values F- 84 F- 84 F-84 Section 7 EVALUATION OF REGULATION PLANS 7.1General 7.2 Lakes Superior and Ontario Regulation Plans Province of Ontario Province of Quebec New York State Upper Michigan 7.3 Lakes Superior, Erie and Ontario Regulation Plan (SEO) Province of Ontario Province of Quebec New York State Upper Michigan 7.4 Lakes Superior, Erie and Ontario Plan with Erie Partially Regulated (SEO-42P) Province of Ontario Province of Quebec New York State Upper Michigan F-85 F-85 F-87 F-87 F-87 F-92 F-92 F-92 F-96 F-96 F-96 F-96 F- 13 F- 13 F- 13 F- 13 F-iv

8 TABLE OF CONTENTS (cont'd) Page 7.5 Lakes Superior, Michigan-Huron and Ontario Regulation Plan (SMHO) Province of Ontario Province of Quebec New York State Upper Michigan 7.6 Lakes Superior, Michigan-Huron, Erie and Ontario Regulation Plan (SMHEO) Province of Ontario Province of Quebec New York State Upper Michigan ANNEX A POWER SUBCOMMITTEEMEMBERS AND ASSOCIATES F- 15 F- 15 F-15 F- 15 F-111 F-111 F-111 F-111 F-118 F-118 F-122 F-v

9 LIST OF TABLES Tab le Page F- 1 Hydroelectric Plants in Canada Using Outflow from Lake Erie F- 16 F- 2 F-3 F-4 Assumed 1985 Non-Power Flow Diversions Estimated 1985 Non-Power Flow Requirements Maximum Permissible Discharge at Beauharnois and Cedars Power Plants F-54 F-66 F-67 F-5 Energy and Capacity Values Used for Evaluating Effects of Regulation Plan on Hydroelectric Power Generation F- 73 F-6 Estimated Load - Mw F- 74 F- 7 Generation Inventory Ontario East System F- 76 F-8 F-9 Forced Outage Rates Projected Inventory on Generation in the New York System in 1985 F-81 F-82 F- 1 Effects of Plan SO-91 on Power - Annual Energy Value F- 86 ($1,) F- 11 Regulation Plan SO-91 Compared to Basis-of-Comparison F-88 Ontario System - Value of Difference in Average Daytime and Nighttime Energy Production and in 1985 Peak Load Meeting Capability F-12 F- 13 Regulation Plan SO-91 Compared to Basis-of-Comparison Ontario System. Average Monthly Energy Production and 1985 Peak Load Meeting Capability Regulation Plan SO-91 Compared to Basis-of-Comparison Hydro Quebec - Beauharnois and Cedars Plants Average Monthly and Annual Energy Outputs and Annual of Value Energy Difference F- 89 F-9 F- 14 Regulation Plan SO-91 Compared to Basis-of-Comparison New York State System - Value of Average Monthly and Annual Energy Production F- 15 Regulation Plan SO-91 Compared to Basis-of-Comparison New York State System - Load Carrying Capacity with Fixed Non-Power Authority Generation F-91 F-93 F-vi

10 Table F- 16 LIST OF TABLES (cont'd) Regulation Plan SO-91 Compared to Basis-of-Comparison U.S. Plants at Sault Ste. Marie, Michigan - Average and Minimum Power Outputs and Annual Values of Capacity and Energy Differences Page F-94 F- 17 Effects of Plan SEO-33 on Power - Annual Energy Value ($1,) F-18 Regulation Plan SEO-33 Compared to Basis-of-Comparison Ontario System - Value of Difference in Average Daytime and Nighttime Energy Production and in 1985 Peak Load Meeting Capability F-95 F-97 F- 19 Regulation Plan SEO-33 Compared to Basis-of-Comparison Ontario System - Average Monthly Energy Production and 1985 Peak Load Meeting Capability F-98 F- 2 Regulation Plan SEO-33 Compared to Basis-of-Comparison F-99 Hydro Quebec - Beauharnois and Cedars Plants Average Monthly and Annual Energy Outputs and Annual of Value Energy Difference F- 21 F-22 Regulation Plan SEO-33 Compared to Basis-of-Comparison New York State System - Value of Average Monthly and Annual Energy Production Regulation Plan SEO-33 Compared to Basis-of-Comparison New York State System - Load Carrying Capacity with Fixed Non-Power Authority Generation F- 1 F-11 F- 23 Regulation Plan SEO-33 Compared to Basis-of-Comparison U.S. Plants at Sault Ste. Marie, Michigan - Average and Minimum Power Outputs and Annual Values of Capacity and Energy Differences F- 12 F-24 F-25 F- 26 F-27 Effects of Plan SEO-42P on Power - Annual Energy Value ($1,) Effects of Plan SMHO-11 on Power - Annual Energy Value ($1,) Regulation Plan SMHO-11 Compared to Basis-of-Comparison Ontario System - Value of Difference in Average Daytime and Nighttime Energy Production and in 1985 Peak Load Meeting Capability Regulation Plan SMHO-11 Compared to Basis-of-Comparison Ontario System - Average Monthly Energy Production and 1985 Peak Load Meeting Capability F- 14 F- 16 F- 17 F- 18 F-vii

11 LIST OF TABLES (cont'd) Tab 1 e F- Regulation Plan SMHO-11 Compared to Basis-of-Comparison Hydro Quebec - Beauharnois and Cedars Plants Average Monthly and Annual Energy Outputs and Annual Value of Energy Difference Page F- 19 F- 29 Regulation Plan SMHO-11 Compared to Basis-of-Comparison F- 11 New York State System - Value of Average Monthly and Annual Energy Production F- 3 F-31 Regulation Plan SMHO-11 Compared to Basis-of-Comparison New York State System - Load Carrying Capacity with Fixed Non-Power Authority Generation Regulation Plan SMHO-11 Compared to Basis-of-Comparison U.S. Plants at Sault Ste. Marie, Michigan - Average and Minimum Power Outputs and Annual Values of Capacity and Energy Differences F-112 F-113 F- 32 F-33 Effects of Plan SMHEO-38 on Power - Annual Energy Value ($1,) F-114 Regulation Plan SMHEO-38 Compared to Basis-of-Comparison F-115 Ontario System - Value of Difference in Average Daytime and Nighttime Energy Production and in 1985 Peak Load Meeting Capability F- 34 Regulation Plan SMHEO-38 Compared to Basis-of-Comparison F-116 Ontario System - Average Monthly Energy Production and 1985 Peak Load Meeting Capability F-35 Regulation Plan SMHEO-38 Compared to Basis-of-Comparison Hydro Quebec - Beauharnois and Cedars Plants Average Monthly and Annual Energy Outputs and Annual Value of Energy Difference F-117 F- 36 Regulation Plan SMHEO-38 Compared to Basis-of-Comparison New York State System - Value of Average Monthly and Annual Energy Production F- 119 F-37 F-38 Regulation Plan SMHEO-38 Compared to Basis-of-Comparison F- 12 New York State System - Load Carrying Capacity with Fixed Non-Power Authority Generation Regulation Plan SMHEO-38 Compared to Basis-of-Comparison F-121 U.S. Plants at Sault Ste. Marie, Michigan - Average and Minimum Power Outputs and Annual Values of Capacity and Energy Differences F-viii

12 LIST OF FIGURES Figure F- 1 St. Marys River at Sault Ste. Marie F- 2 St. Marys River Fall from Lake Superior at Marquette to C.H.S. Gauge 11 F-3 St. Marys'River Backwater Slopes C.H.S. Gauge 11 to Great Lakes Powerhouse Forebay for Various Diversions F-4 St. Marys River Gauge Relationship between C.H.S. Gauge 12 and Great Lakes Powerhouse Tailwater F- 5 St. Marys River Backwater Slopes Lake Huron to C.H.S. Gauge 12 January - March F-6 St. Marys River Backwater Slopes Lake Huron to C.H.S. Gauge 12 April - December F- 7 St. Marys River Total Output from Canadian Plants Based on Gross Head at Great Lakes Power Corporation Plant F- 8 Plan of Niagara River - Lake Erie to Lake Ontario F-9 Niagara River - Detail Location of Hydroelectric Power Plants and Diversion Works F-1 Total Energy Output (Av.Mw) for Inflow to Grass Island Pool F-11 Niagara River Diversion to S.A.B. No. 1 and 2 versus Grass Island Pool Level for Canal Crossover Level 54. between Tunnels and Power Canal F-12 Niagara River S.A.B. No. 2 Tailwater Elevation versus Niagara River Flow F-13 Sir Adam Beck - Niagara G.S. No. 1 and 2 Estimated Unit Fall - Discharge Relationship Material Dock (Gauge 5) to Canal Crossover Gauge at Two Tunnels and Power Canal (After Rehabilitation) F-14 Niagara River Flow Past Control Structure with all Gates Closed versus Grass Island Pool Elevation F-15 Niagara River Adjustment to Average Monthly Energy Output of Present Canadian Power Plants for Daily Mean Flow Deviation versus Inflow to Grass Island Pool Page F-4 F-8 F-9 F-1 F-11 F- 12 F- 13 F-17 F- 18 F-23 F- 25 F- 26 F-27 F- F- 3 F-ix

13 LIST OF FIGURES (cont'd Figure Page F-16 Niagara River Daily Energy Gain or Loss from Operation F- 31 of S.A.B. No. 2 Pump G.S. versus Inflow to Grass Island Pool F- 17 to PASNY Energy-Flow Relationship January F- - December F- 33 to F-44 F-29 Total Peak Output versus Inflow to Grass Island Pool F-3 Niagara River Tailwater Elevation at S.A.B. No. 2 at Time of Peak versus Inflow to Grass Island Pool F-31 Backwater Slopes Lake Ontario to Moses-Saunders Powerhouse Open Water Conditions F-32 Backwater Slopes Lake Ontario to Moses-Saunders Powerhouse Ice Cover Conditions F-33TailwaterStage-DischargeCurve F-34 Average Economy Factor for Moses-Saunders Plants versus Gross Head (Best Efficiency Operating Range) F-35 Combined Moses-Saunders Plant Output - Discharge Relationship F-36 Plan of Soulange Section of St. Lawrence River F-37 Discharge Relationship between Lake St. Francis Outflow and Lake Ontario Outflow F-38 Relationship between Total Lake St. Francis Outflow and Elevation of Upper Beauharnois Lock F-39 Stage-Discharge Relationship for Lake St. Louis F-4 Power Output-Head-Discharge Relationship for Beauharnois Powerhouse F-41 Power Output-Discharge Relationship for Cedars Powerhouse F-47 F-49 F-55 F-56 F-57 F-59 F-6 F-63 F-65 F-68 F- 7 F- 71 F- 72 F-X

14 LIST OF APPENDICES (bound separately) APPENDIX A - HYDROLOGY AND HYDRAULICS A detailed description of the hydrology and hydraulics of the Great Lakes system, including an outline of the "state of knowledge" of the various factors which govern its water supply and affect the response of the system to its supply. APPENDIX B - LAKE REGULATION A documentation of the studies related to the regulation of all the Great Lakes and various combinations of them and a presentation of an array of plans for regulating the levels of these combinations. APPENDIX C - SHORE PROPERTY A documentation of the methodology developed to estimate in economic terms the effects of changes in water level regimes on erosion and inundation of the shoreline, marine structures and water intakes and sewer outfalls, and of the detailed evaluations of selected regulation plans. APPENDIX D - FISH, WILDLIFE AND RECREATION A documentation of the methodology developed to assess the on effects fish, wildlife and recreation of changes in water level and outflow regimes and of the detailed evaluations of the effects of selected regulation plans on these interests. APPENDIX E - COMMERCIAL NAVIGATION A documentation of the methodology applied in the assessment of the potential benefit or loss to shipping, using the Great Lakes-St. Lawrence navigation system, as a consequence of changes in lake level regimes and the evaluation of the economic effects on navigation of regime changes that would take place under selected regulation plans. APPENDIX F - POWER A documentation of the methodology applied in the assessment of the effects of regulatory hydroelectric power production at installations on the outlet rivers of the Great Lakes and of the detailed evaluation of the economic effects of selected regulation plans on the capacity and energy output of these installations in terms of the costs to the associated power systems. APPENDIX G - REGULATORY WORKS A description of the outlet systems of the lakes, problems to be faced in providing new regulatory facilities at the outlets, site investigations carried out, design criteria and methods used, environmental factors considered, and design and cost estimates of engineering works required for selected regulation plans. F-xi

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16 Section 1 INTRODUCTION 1.1 General By the terms of the Reference of October 7, 1964, the Governments of Canada and the United States requested the International Joint Commission If... to determine whether measures within the Great Lakes Basin can be taken in the public interest to regulate further the levels of the Great Lakes or any of them and their connecting waters so as to reduce the extremes of stage which have been experienced, and... for the purpose of bringing about a more beneficial range of stage for, and improvement in: (a) domestic water supply and sanitation; (b) navigation; (c) water for power and industry; (d) flood control; (e) agriculture; (f) fish and wildlife; (g) recreation; and (h) other beneficial public purposes1f. The International Great Lakes Levels Board was established by the International Joint Commission on December 2, 1964, to initiate and direct the studies required to answer the Reference. This Appendix forms part of the final report of the International Great Lakes Levels Board to the International Joint Commission, dated December 7, It deals with hydroelectric power installations on the connecting channels of the Great Lakes and on the St. Lawrence River and evaluates various regulation plans in terms of their effects on capacity and energy output of the installations and the monetary value of any changes in these two components. 1.2 Organization The International Great Lakes Levels Board set up a Working Committee on January 6, 1965, to assemble the data, organize field activities and conduct studies necessary to answer the Reference. The Working Committee established Subcommittees for each of the major phases of the study. The Power Subcommittee was composed of six members. A list of those people who have contributed to the work of the Subcommittee is provided in Annex 'AI. The Power Subcommittee's assignment was to develop the necessary methodology to evaluate the effect of regulation on hydroelectric power generation and to make the necessary economic evaluations. 1.3 Procedure of Power Study One of the interests that would be affected by regulation of any or all of the Great Lakes is hydroelectric power since such installations are located on all the international connecting and outlet channels of the Great Lakes except the St.Clair-Detroit Rivers. F- 1

17 Determination of the effects of regulation on hydroelectric power installations utilizing the levels and flows of the Great Lakes system, under the basis-of-comparison condition and under the selected regulation plans for various combinations of lakes (SO, SEO, SMHO, SMHEO) has been carried out by the Power Subcommittee. The determination of the effect of a regulation plan on hydroelectric power installations is generally divided into two parts; the effect on dependable capacity and energy output; and second, the monetary evaluation of any changes in these two components, as measured by effects on electric system costs. Because Beauharnois and Cedars (Quebec) are run-of-river plants, only the effects on energy production were evaluated. It was considered that for purposes of this study system analysis for these plants would not be necessary. The year 1985 was chosen for use in the power studies because of the uncertainty of fuel costs which limits the reliability of projections. In determining the effect of a regulation plan on hydroelectric power output, the results of operation under the plan was compared with results under a basis-of-comparison condition. Specifically, the basisof-comparison consists, in part, of Lakes Superior and Ontario regulated according to the methods presently in effect which are the September 1955 Modified Rule of 1949 and plan 1958-D respectively, and Lakes Michigan-Huron and Erie unregulated. The outlet conditions for Lake Huron are those of 1933 or 1962 depending on the plan being evaluated and for Lake Erie, For the basis-of-comparison and each regulation plan, it was assumed that the above conditions, modified by present diversions into and out of the lakes, and by the estimated 1985 navigation flow requirements for lockages past the control structures, would apply at a constant rate over the 68-year study period ( ). A complete description of the basis-of-comparison is given in the main report. The estimated 1985 navigation requirements were based on the traditional navigation season and did not allow for the requirements of winter navigation. This appendix presents the methods employed by the Subcommittee for computing and evaluating the effects of the various regulation plans under load and power supply conditions estimated to obtain in 1985, on all related existing hydroelectric installations in Canada and the United States on the St. Marys River at Sault Ste. Marie, on the Niagara River near Niagara Falls and on the St. Lawrence River near Cornwall and Beauharnois. The existing installations involved in this study have a total installed capacity of 7,969,18 kilowatts (kw) of which 4,87,58 kw are in Canada and 3,161,6 kw are in the United States. The estimated power supplies required in New York State and the Ontario Hydro System to meet anticipated peak loads plus reserves in 1985 amount to 41,38 megawatts (Mw) and 35,726 Mw, respectively. F- 2

18 Section 2 ST. MARYS RIVER POWER PLANTS 2.1 General Description The St. Marys River forms the outlet of Lake Superior. From Whitefish Bay, at the east end of Lake Superior, the river flows in a general southeast direction to Lake Huron, a distance of approximately 7 miles. From its headwater on Whitefish Bay to its outlet on Lake Huron, the river falls about 22 feet, most of which (2 feet) occurs in the mile long St. Marys Rapids at Sault Ste. Marie, Michigan and Ontario. At Sault Ste. Marie, various man-made facilities have been constructed since Since 1921 these have enabled complete control of the outflow from Lake Superior and consist of navigation locks, hydroelectric power plants and compensating works. All water flowing out of Lake Superior through the St. Marys River must pass through one of these facilities. The general arrangement of plants and water level gauges used in the computation are shown on Figure F Canadian Power Plants There are two plants on the Canadian side of the St. Marys River; one hydroelectric plant owned by the Great Lakes Power Corporation and the other a hydraulic plant driving a groundwood mill owned by the Abitibi Pulp and Pape: Company. Both plants employ the same diversion canal and have an average gross head of 2 feet. Water requirements for these two plants prior to 197 amount to approximately 25, cfs. In 197, installation of an 8, horsepower electric motor at the Abitibi Plant eliminatna the use of direct hydraulic-powered woodgrinders, which resulted in a decrease of about 7, cfs in water requirement for power production on the Canadian side of the river. However, the plant is still used to discharge water from Lake Superior as required. The Great Lakes Power Corporation's plant has units and a total installed capacity of 21,5 kw United States Plants There are two hydroelectric power plants located on the United States side of the St. Marys River. The United States Government plant, which contains four units is located at the foot of the falls, has a total capacity of 16, kw. The plant also has one unit located at the head of the falls with a total capacity of 2,3 kw; all water used is taken from the same diversion canal and totals approximately 12,7 cfs at plant capacity. The Edison Sault Electric Company plant, located below the rapids, is served by a 2 1/2 mile long diversion canal. This plant has a total capacity of 41,3 kw at a head of 2 feet with a water usage of approximately 3,5 cfs at rated plant capacity. F- 3

19 w ~ <{ ~ w '(i) ~ :J :L ~! I- ~ <{.21 a: u.w > ir: (J) >- ~ ~ ~ F-4

20 2.2 Assumptions The assumptions adopted for computing the total energy and peak capacity outputs for any given regulated mean monthly Lake Superior outflow and level and corresponding Lake Huron level are given in the following subsections General The estimated 1985 navigation flow requirements by months and halfmonths are : March Apri 1 May June July August September October November December - 2nd half 1 cfs - 1st half 4 cfs 2nd half 1,1 cfs 1,5 cfs 1,6 cfs 1,7 cfs 1,7 cfs 1,5 cfs 1,5 cfs 1,2 cfs - 1st half 1,1 cfs As the regulation periods are monthly, the estimated navigation flow requirements for March, April and December have been averaged to the nearest 1 cfs as cfs for March, 8 cfs for April and 6 cfs for December Canadian Plants (1) Both plants are operated on a run-of-river basis; hence, in any month, peak capacity and the rate at which energy is generated are the same. (2) The water available for Canadian use is taken as the lesser of the maximum capacity of Canadian plants of 26,5 cfs or the Canadian share computed as: Qo - P, - 5, - + 5, cfs Qc 2 Q = Canadian Diversion C where Qo = Lake Superior mean monthly flow in cfs = Estimated 1985 navigation flow requirement +2, Qm cfs spill through compensating works 5, cfs = average Long Lake-Ogoki Diversion. This diversion assumed to be available to Canadian plant only. (3) Head losses for various reaches of the St. Marys River would be the same as those that occurred during the period 195 through 1964 for which daily information is available. F-5

21 (4) The Abitibi Pulp and Paper Company hydraulic-powered groundwood mill would be available for operation United States Plants (1) The permissible diversion by U.S. plants is assumed to be the greater of the two amounts computed as: Qus - Qo - a - 5, - Qus Qo - Qm - Qc 2 or where 8, = United States Diversion Qo, Qc, and Qm are as defined in Section Methodology for Determining Capacity and Energy Output The method used to compute power output from the St. Marys River plants has been developed by Ontario Hydro and the U.S. Army Corps of Engineers in cooperation with the Great Lakes Power Corporation and the Edison Sault Power Company. The methods outlined below compute the output from the existing facilities under the basis-of-comparison conditions of levels and flows, and the output which would result had a given regulation plan been in operation over the same period. The general approach employed is as follows: (1) Determine the head loss between Lake Superior and the forebay of the plants to obtain forebay level. (2) Determine the head loss between the tailrace of the plants and Lake Huron to obtain tailwater level. (3) Compute head on the plants as the difference between forebay and tailwater levels. (4) Compute the permissible power diversion by the procedure outlined in assumption 2.2. (5) Determine total output from output-head-discharge curves. Details are given in the following subsections of the methods employed for computing total output and the derivation of the various relationships Canadian Plants The head loss relationships for the various reaches of the St. Marys River were determined from the following mean monthly recorded level and flow data for the period January 195 to December 1964: diversions through each Canadian plant and water levels of Lake Superior at Marquette, Michigan, Lake Huron at Harbor Beach, Michigan and St. Marys F-6

22 River at Canadian Hydrographic Service (CHS) gauges 11 and 12, plant forebays and plant tailraces. (1) Head loss Lake Superior to CHS gauge 11: Two relations were required; one for the ice cover period, January to March, and the other for the open water period, April to December. The curves are shown on Figure F-2 and their equations are: for January-March, Q = 135,115JF and for April-December, Q = 187,7OJF, where F is fall or head loss in feet. (2) Head loss CHS gauge 11 to Great Lakes Power plant (GLP) forebay: A single relationship for each diversion rate is applicable to all months and is shown on Figure F-3. The equation of the unit fall relation is: Mean Water Surface El = x 4 fi Also shown on Figure F-3 is the diversion from which maximum power can be generated for low levels at CHS gauge 11. (3) Head loss between headwater levels of the two plants: A gauge relation indicated that the Abitibi mill headwater was on the average about.1 foot lower than GLP plant headwater. (4) Head loss between tailwater levels of the two plants: A gauge relation of the mean monthly levels during the months in which discharge through the Abitibi mill was greater than 6, cfs indicated that the mill tailwater averaged about.7 foot higher than the GLP plant tailwater. (5) Head loss GLP plant tailrace to CHS gauge 12: Head loss determined by gauge relation derived from mean levels during the months in which the total Canadian power diversion was greater than 24, cfs, Figure F-4. The relation appeared to be independent of season. (6) Head loss CHS gauge 12 to Lake Huron: Head losses determined by unit fall relationships between levels at CHS gauge 12 and Lake Huron at Harbor Beach, Michigan and Lake Superior outflow for the ice cover period January to March, and for the open water period, April to December. These relations are shown on Figure F-5 and Figure F-6. The equations are : January to March: Mean Water Surface Elevation = x 4 April to December: Mean Water Surface Elevation = x 4 fi The total output-discharge-head relationship for the present Canadian power plants has been derived from data supplied by the Great Lakes Power Corporation, and is shown on Figure F-7. JF F- 7

23 .6.5 BASED ON RECORCED MONTHLY MEAN VALUES, JANUARY 195- DECEMBER 1964.L t; W LL z_ h LL.: v J -I a LL.:.. " " I J I I I I I I I I L" go LAKE SUPERIOR OUTFLOW (Q)-THOUSANDS OFC.F.S. Figure F-2 ST. MARYS RIVER FALL FROM LAKE SUPERIOR AT MARQUETTE TO CHS GAUGE 11 F- 8

24 61 m m Dl 4 v n 1 2 I W cn I 6C LL? a cn W Y a J Q W LL u k a Z k a W LT sa W c n W I I I I 6 I 6 1 WATER SURFACE ELEV. AT C.H.S. GAUGE Oll-IGLD(1955) Figure F-3 ST. MARYS RIVER BACKWATER SLOPES CHS GAUGE 11 TO GREATLAKESPOWERHOUSE FOREBAY FOR VARIOUSDIVERSIONS F

25 WATER SURFACE ELEV.AT C.H.S. GAUGE 12"IGLD(1955) Figure F-4 ST. MARYS RIVER GAUGE RELATIONSHIP BETWEEN CHS GAUGE 12 AND GREAT LAKES POWERHOUSE TAILWATER F- 1

26 v) I I- F- 11

27 I W 3 Q W + I ; 581 I-?1 a I F N s 1 W 579

28 19 I I I I I I I GROSS HEAD IN FEET Figure F-7 ST. MARYS RIVER TOTAL OUTPUT FROM CANADIAN PLANTS BASED ON GROSS HEAD AT GREAT LAKES POWER CORPORATION PLANT F- 13

29 The headwater and tailwater levels used are those of the GLP plant and are based on average head difference between this plant and the mill. It has been estimated that the head at the Abitibi mill is.8 foot less than that at the GLP plant. The Abitibi mill was considered to generate 12,5 hp from 7,2 cfs at a gross head of 18 feet. This head corresponds to 18.8 feet at the GLP plant; the plant efficiency based on 18.8 foot head is 81.4% (provided by GLP). This efficiency was applied to 12,5 hp (9,325 kw) to determine the quantity of water required by the mill over the full range of expected heads. The GLP plant uses the remainder of the entitlement of water available at an overall efficiency of 63% (specified by GLP). The resultant overall power related to head for a range of total diversion between 2,5 and 26,5 cfs is shown on Figure F United States Plants Head Loss Relationship: The head available at each plant was determined as the difference in elevation between the two lakes, less the loss from Lake Superior to the plant forebay, and the loss from the plant tailwater to Lake Huron. The relationships employed were as follows : (1) Head loss from Lake Superior to Southwest Pier gauge, located in the proximity of the entrance to the Edison Sault Electric Company power canal, Fall = Qo x (2) Head loss for U.S. Slip gauge (USS), located near the tailrace for the Edison Sault plant, to Lake Huron Qo = 193 (USS )1'5 x (Fall -.9)o'2 during the ice period and Qo = 165 (USS )1-5 x (Fall -.9)'4 during the open water period. (3) Head loss from Southwest Pier gauge to U.S. Slip gauge is used to compute the losses through the two power plants. The loss through the Edison Sault plant is computed by subtracting the head loss in the canal from the SWP-USS loss. The loss in the canal is limited to 3.5 feet by the power company to keep excessive velocities from damaging the canal walls. The head loss in the Edison Sault power canal was determined from: Head loss = 27,8 Q26 / '(SWP )5'2 where Q is the canal flow in thousands of cfs SWP is water surface elevation at Southwest Pier gauge. F-14

30 For the U.S. Government plant, the head loss consists of the river loss from Southwest Pier gauge to the regulating works, the loss in the head race to the plant forebay, the loss in the tailrace and the river loss from the tailrace to U.S. Slip gauge. The discharge through the Government plant is practically constant at about 12,7 cfs and accordingly there is no variation of head loss in the head race or tailrace due to discharge. There is a small variation in head loss in the tailrace which is related to the river stage below the rapids. No accurate relationships between the river losses and the river flows have been established but they are very small in magnitude compared to the overall head. The variations in these small losses have insignificant effect on the evaluation of the various regulation plans. For the purposes of the present evaluations, the river losses and head and tailrace losses were assumed constant at.6 foot. Total Output Relationships: The total output relationships for each of the United States plants are as follows: (a) Power output by U.S. Government plant P = 155 H - 9 for values of H of 21.5 or less P = 4 H - 75H2-27,56 for values of H of 21.5 or more where P is a power output in kw for an assumed constant plant water use of 12,7 cfs and H is the net head on the plant in feet. (b) Power output by Edison Sault plant Pa =.71 (62H (89.5H - 39)Q) when Q is less than H P = Pa - 13 (Q H) w k 1.6 en Q exceeds H PC = Pb (Q H) 1.6 when Q exceeds H and H exceeds 17 In the above relations, Pa, Pb and PC are the power outputs in kw, Q is the plant water use in thousands of cfs, and H is the net head on the plant in feet. F- 15

31 Section 3 NIAGARA RIVER POWER PLANTS 3.1 General Description The outflow from Lake Erie which is utilized for power is diverted to the various hydroelectric plants by means of the Welland Canal and by several structures from the Niagara River at the Grass Island Pool about a mile above Niagara Falls. Plants in Canada are served from both sources, whereas in the United States diversion is totally from the Niagara River at the Grass Island Pool, Figure F-8 shows the general location of the Niagara River and Figure F-9 shows the detail locations of diversion structures and hydroelectric power plants at Niagara Falls Canadian Plants There are eight hydroelectric power plants on the Canadian side of the Niagara River which take their water either directly from the river or from Lake Erie via the Welland Ship Canal. Table F-1 lists the plants, the source of their water supply, number of units, rated head and installed capacity. In the power studies it has been assumed that the Rankine plant which is owned and operated by the Canadian Niagara Power Company (a U.S. -owned company) will not be in operation in TABLE F-1 HYDROELECTRIC PLANTS IN CANADA USING OUTFLOW FROM LAKE ERIE Plant Source of Water Supply No. of Units Rated Head (feet) Installed Capacity ( kw) DeCew Falls No. 1 DeCew Falls No. 2 Sir Adam Beck No. 1 Sir Adam Beck No. 2 Pumping Station and Generating Station Ontario Power Toronto Power Canadian Niagara Power Co. (Rankine) Welland Canal Welland Canal Niagara River Niagara River Niagara River Niagara River Niagara River Niagara River Niagara River ,9 115,2 4 3,9 1,223,6 176,7 11,5 64, 94,7 F- 16

32 Figure F-8 PLAN OF NIAGARA RIVER-LAKE ERIE TO LAKE ONTARIO F- 17

33 TUNNEL NO. 1 ISLAND POOL CHI PPAWA MATERIAL DOCK G.S. No. 2 INTAKES ROBERT MOSES PLANT LEWISTON PUMPING- GENERATING PLANT - - SCALE IN FEET H Figure F-9 NIAGARA RIVER-DETAIL LOCATION OF HYDROELECTRIC POWER PLANTS AND DIVERSION WORKS

34 3.1.2 United States Plants The existing United States hydroelectric plants are the Robert Moses Niagara Power Plant and the Lewiston Pumping-Generating Plant. These plants have 13 and 12 units respectively with rated heads of 3 and 85 feet. Their installed capacities are 195 megawatts and 24 megawatts respectively. Both plants are owned and operated by the Power Authority of the State of New York. 3.2 Methodology for Determining Energy and Peak Capacity Output This section presents the assumptions and methods developed by Ontario Hydro and the Power Authority of the State of New York for computing energy and peak capacity outputs obtainable from Canadian and United States hydroelectric power plants in the Niagara area. These methods are used to compute the outputs which would be available from existing facilities with basis-of-comparison Lake Erie outflows, and the outputs which would be available from existing facilities with the Lake Erie outflows which result from the various regulation plans Assumptions (1) For any Grass Island Pool inflow the diversion entitlements for Canada and the United States would be determined from the equations given in (4). (2) The order of priority in which the Canadian plants were assumed to use the available diversion is DeCew, Sir Adam Beck (SAB) Nos. 1 and 2 and the pumping-generating stations, Ontario Power and Toronto Power. (3) The Niagara Falls flow requirements as set forth in the International Niagara Treaty of 195 would be complied with. These consist of a flow of not less than 1, cfs over the falls between the hours of 8:OO A.M. EST to 1O:OO P.M. EST from April 1 through September 15 and between the hours of 8:OO A.M. EST and 8:OO P.M. EST from September 16 through October 1, or EDT whenever it is in effect in either country at Niagara Falls. The flow over the falls at any other time to be a minimum of 5, cfs Basic Data Except as noted below, the data used in these computations are given in Volume 2 Coordinated Basic Data of Appendix "B" Lake Regulat ion : (1) Mean monthly recorded Lake Erie outflows ( ). (2) Mean monthly Lake Erie outflows resulting from regulation plans ( ). F- 19

35 (3) The mean daily Niagara River recorded flows at Buffalo given in Table 5 of the report on Lake Erie Outflows 186 to 1964, dated June 1965 by the Coordinating Committee on Great Lakes Basic Hydraulic and Hydrologic Data and as coordinated by the International Niagara Committee through (4) The mean monthly recorded Welland Canal diversions from Lake Erie as given in Table 1 of the Coordinating Committee's report on the above report through (5) The recorded mean monthly Lake Erie outflows given in Table 7 of the above report through (6) Niagara River monthly mean local inflow from the above. (7) Head losses and diversion capabilities for the water supply tunnels and canals were determined by actual field tests. (8) Diversion capabilities and power output - flow relations for each plant were determined from field tests augmented by operating experience Derived Data Depending upon the regulation plan being evaluated and operating experience, adjustments were made to the data as follows: (1) Lake Erie mean daily basis-of-comparison and regulated outflows : Mean daily Lake Erie basis-of-comparison outflows and mean daily outflows from those regulation plans for which no control structure would be required at the lake outlet were derived from mean daily recorded Niagara River flows at Buffalo by adding to these flows the appropriate mean monthly recorded Welland Canal diversion and the difference between basis-of-comparison and recorded mean monthly Lake Erie outflows, or the difference between the regulated and recorded mean monthly outflows. As mean daily recorded river flows are available only since January 1, 1926, the period for which basis-of-comparison or regulated mean daily Lake Erie outflows can be computed is from this date to December 31, 1964 (39 years). The flow data used in these computations are identified in Section (3,4,5). Mean daily Lake Erie outflows from trial regulation plans which would require a control structure at the lake outlet were considered to be the same as the mean monthly regulated outflows. As the peak outputs computed from these outflows are to be compared with the peak outputs computed from mean daily basis-of-comparison outflows, only those regulated outflows from January 1, 1926 to December 31, 1964 were considered. F-2

36 (2) Niagara River flow into the Grass Island Pool: Mean daily or mean monthly Niagara River flows into the Grass Island Pool were derived from corresponding Lake Erie outflows by subtracting the Welland Ship Canal and New York State Barge Canal assuming navigation flow requirements as of 1985 and a constant flow of 6,4 cfs to the DeCew power plants, adjusting for the effect of Welland Ship Canal flow variations on Niagara River flow and adding local Niagara River inflow. The net adjustments to Lake Erie outflows each month are: January February March April May June July August September October November December The sources of the adjustments are 3,3 cfs 3,6 cfs 2,9 cfs 6,7 cfs 1,5 cfs 1,9 cfs 1,8 cfs 1,9 cfs 1,6 cfs 1,5 cfs 9,8 cfs 5,2 cfs as follows: (a) The monthly and half-monthly Welland Ship Canal and New York State Barge Canal flows for the projected 1985 navigation requirements. (b) Adjustments for the effect on Niagara River flows of monthly variations in Welland Canal navigation flows, developed by Ontario Hydro. (c) The Niagara River monthly mean local inflows, given on page 13 of the Coordinating Committee's Report on Lake Erie Outflows, (3) Determination of flproperfl Grass Island Pool level: The "proper" level of Grass Island Pool depends on flow and is computed from the basic equation (Q - 16,) l'properll level = io,ooo where Q is the Niagara River flow into the pool in cfs. The "proper" level is the level which is determined from the 1953 flow-level relationship. This equation is given in the International Joint Commission's 1953 Report on the Preservation and Enhancement of Niagara Falls. Allowance for the effect of aquatic weeds, the growth of which varies during the year, is made by adding to the result of this equation a number which ranges from to.32 foot depending on the month. This set of monthly adjustments was developed by analysis of several years of recent operating records. F-21

37 (4) The diversion entitlements for Canad and the United States for power generation for any Grass Island Pool inflow are based on Article 111, Niagara Diversion Treaty,, 195: Canadian entitlement = 1/2 (Grass Island Pool Inflow U.S. entitlement = 1/2 (Grass Island Pool Inflow - Falls flow ) These equations add the 64 cfs used at the DeCew plants to the total power water available and reserve the approximately 5 cfs Long Lake- Ogoki diversion into Lake Superior for Ontario Hydro use Total Energy Output Computations for Canadian Plants The energy outputs obtainable from the Canadian power plants during daytime and nighttime hours were computed monthly over the period January 19 to December 1967 for the basis-of-comparison and for each regulation plan. Daytime energy was considered to be that generated between 7:OO A.M. and 11:OO P.M. and nighttime energy, that generated between 11:OO P.M. and 7:OO A.M. The method of computing these daytime and nighttime energy outputs for each month of the 68- year period is described in the following paragraphs: (1) Total energy output in average megawatts is obtained from a relationship between Niagara River flows into 'Grass Island Pool described in Section (2) and the available energy output. This relationship is derived for two periods; tourist season days and tourist season nights or non-tourist season and shown graphically on Figure F-1. For the tourist season, two values of energy output are obtained, one for tourist hours (14 or 12 hours/day) and another one for non-tourist hours (1 or 12 hours/day). Each of the relationships has been derived by computing energy output for 2 to 25 flows which represent the expected flow range. (2) The order of priority of the plants is as described in (4). (3) The diversion to DeCew is considered to be constant at 64 cfs. Gibson and Moody Lakes provide some forebay storage so the daytime energy has been taken as 156 Mw for 16 hours per day and nighttime energy has been taken as 81 Mw for 8 hours per day. (4) The diversion to the SAB plants was taken as the diversion available after 6,4 cfs were allotted to DeCew or the flow that can be diverted through the Beck tunnels and canals with a given Grass Island Pool level and a forebay level of 54 feet (assumed normal minimum operating level), whichever is the lesser. The diversion capacity of the SAB tunnels and canals for a given head varies with the season. F-22

38 2 19 LEGEND PRESENT CONTROL STRUCTURE (i.e. LAKE ERIE NOT REGULATED) EXTENDEDCONTROLSTRUCTURE " (i.e. LAKEERIEREGULATED) 18 z > a 3 a 5 >. W 15 NON-TOURIST SEASON AND TOURIST SEASON NIGHTS 14 TOURIST SEASONDAYS 13 Z W a -? cn N w Z a d a -J 1 I- O t= 9 8 NOTE ENERGY VALUES FROMCURVES REQUIRE ADJUSTMENTS FOR: 1. DAILY FLOW DEVIATION FROM MONTHLYMEAN (FOR PRESENTCONTROLSTRUCTUREONLY) 2. SAB #2 PUMPING-GENERATING PLANT OPERATION 3. MAXIMIZING DECEWENERGY 7 6 INFLOWTO GRASS ISLAND POOL-1's BASES 1. MEAN NIAGARA RIVERWEEDEFFECT 2. MINIMUM S.A.B.NO. 2 FOREBAY S.A.B.NO. 2 TW.ELEV. BASED ON MEAN LAKE ONTARIO ELEVATION ONTARIO POWERG.S. CAPACITY 8,3 CFS. (12 UNITS) 5.TORONTOPOWERG.S. CAPACITY 9, CFS. (7 UNITS) 6. CANADIANNIAGARA POWER OUT OFSERVICE CFS NIAGARA AREA PRESENT CANADIAN POWER PLANTS

39 The diversion was read from Figure F-11 which gives maximum SAB diversion rate for a given Grass Island Pool level. (5) If the water available to the SAB plants exceeds the capacity of its diversion facilities, then SAB forebay level was assumed to be 54 feet and it diverts to full capacity. If the water available is less, the forebay level will be above 54 feet and was computed by use of the unit fall relationship shown on Figure F-13. (6) The SAB tailwater level was obtained from the curve on Figure F-12 relating river flow and tailwater level for an average Lake Ontario level 3f (7) Gross head on the SAB plants was computed as the difference between the forebay level computed as described in item (5) and the tailwater level computed as described in item (6). (8) The SAB component of the energy output shown on Figure F-1 was computed from the flow diverted to SAB, item (4), and the gross head, item (7). An economy factor of 22. kw/cfs at a gross head of 291. feet is typical for the SAB plant. (9) The diversion available to the Ontario Power plant is the allowable Canadian diversion less the diversions to the DeCew and SAB plants less the Canadian share of any additional water that is required, under certain river flows, to maintain the proper level of Grass Island Pool. Figure F-14 shows the relation between flow past the control structure and the level of the Pool. It has been assumed that if the flow around the end of the control structure is less than shown on the curve, the difference will be supplied equally by Ontario Hydro and the Power Authority of the State of New York (PASNY). It is assumed that the Ontario Power plant can take all of the available diversion up to its capacity (83 cfs). Outputs from the Ontario Power plant were computed as 12.6 kwh for each cfs hour diverted. (1) The diversion available to the Toronto Power plant is that not utilized by Ontario Power. The quantity that it diverts is the lesser of the available diversion or its diverting capability of 9 cfs. Outputs from the Toronto Power plant were computed as 7.1 kwh for each cfs hour diverted. (11) Total energy outputs shown on Figure F-1 are the sum of the outputs of the individual plants described in items (8,9 and 1). The graphical relationships are typical of average or normal conditions. Other factors which affect the energy outputs but which could not be included readily in graphical form were treated as adjustments and are described under items 12,13,14. (121 For the basis-of-comparison and regulation plans not requiring a control structure at Lake Erie outlet, the lake outflows would vary somewhat erratically during the month. Since flows higher than certain llmits result in diminishing efficiency in the use of water diverted F- 24

40 NOTE: THIS CURVE WAS COMPUTED FROM UNIT-FALL DISCHARGE RELATIONSHIP SHOWN ON Figure F-12 FOR TOURIST AND NON-TOURIST SEASONS. TOTAL DIVERTED FLOW-S.A.B. NO. 1 &.2 THOUSANDS OF CFS Figure F-11 NIAGARA RIVER DIVERSION TO S.A.B. NO. 1 AND 2 VERSUS GRASS ISLAND POOL LEVEL FOR CANAL CROSSOVER LEVEL 54. BETWEEN TUNNELS AND POWER CANAL F- 25

41 25 1.O h m E I N Z u) I- a a W l- a 3 - a + COMPUTED FROM M.W.S.= I-,2164 X lo3 Q/ fi BASED ON MONTHLY MEAN OBSERVED LEVELS AND FLOWS FOR THE MONTHS APR.TO DEC.PERIOD-APRIL 1961 TO JULY 1967 RELATIONSHIP BASED ON LAKE ONTARIO ELEVATION IGLD (1955) C I I I I I I I I NIAGARA RIVER FLOW-THOUSANDS OF C.F.S. DOWNSTREAM S.A.B. Figure F-I 2 NIAGARA RIVER S.A.B. NO. 2 TAILWATER ELEVATION VERSUS NIAGARA RIVER FLOW

42 f 556 i- 3 a n z I? I a z a 55 NOTES: RELATIONSHIP IS BASED ON RELATIONSHIP SHOWN ON ONTARIO HYDRO DWG. NF DATED DEC. 17/64 WHICH INCLUDES THE EFFECT OF REHABILITATING THE QUEENSTON POWER CANAL TO INCREASE THE CAPACITY BY AN ESTIMATED 65 CFS. AT MATERIAL DOCK ELEV. OF 561. AND CROSSOVER ELEV. AT 538. FOR TOURIST AND NON-TOURIST SEASON I I I I I I I 12,4 12,6 12,8 13, 13,2 13,4 13,6 13,8 14, 14,2 14,4 14,6 14,8 15, 15,2 15,4 QWF Figure F-13 SIR ADAM BECK-NIAGARA G.S. NO. 1 AND 2 ESTIMATED UNIT FALL-DISCHARGE RELATIONSHIP MATERIAL DOCK (GAUGE 5) TO CANAL CROSSOVER GAUGE AT TWO TUNNELS AND POWER CANAL (AFTER REHABILITATION)

43 F- C

44 for power, the energy output available from the mean monthly flow may not be equivalent to the energy output available from the individual daily flows which produced that particular mean monthly flow, The correction for each month related to Grass Island Pool inflow was developed from an analysis of flow variations that are typical of each calendar month. These relationships are shown in Figure F-15. (13) 131 Mw of DeCew output were included in the preparation of Figure F-1. Daytime energy from this plant averages 25 Mw more than daily average output and nighttime energy averages 5 Mw less than daily average. (14) An adjustment for SAB #2 Pumping-Generating plant operati-on was made which resulted in a gain in total daytime energy and loss in total nighttime energy. These gains and losses, related to Niagara River flow, are shown on Figure F-16. It is assumed that the SAB #2 pump storage reservoir is filled each night and the water fully uti.lized during the following day. (15) The total daytime energy is computed as the sum of the energy for tourist and non-tourist hours between 7:OO A.M. and 11:OO P.M. from Figure F-1 corrected as described in items 12,13, plus the daytime energy released from the reservoir for the appropriate season as described in item 14. (16) Nighttime energy is the sum of the energy for the period between 11:OO P.M. and 7:OO A.M., which are all non-tourist hours for all months of the year, computed from Figure F-1 and corrected as described in items 12 and 13 less the nighttime energy stored in the reservoir for the appropriate season as described in item 14. (17) Total daytime and nighttime energy outputs in a month were determined by multiplying the daily energy for each category by the number of days in the month Total Energy Output Computations for United States Plants The energy outputs obtainable from the U.S. PASNY power plants during daytime and nighttime hours were computed for the basis-ofcomparison and for each regulation plan for a range of Lake Erie outflows for each month of the year over the period January 19 through December The energy available for the basis-of-comparison and each regulation plan was divided into weekday daytime, weekday nighttime and weekend components. Trial dispatches have been made of energy sources into load duration curves representing Sunday, average weekday, peak weekday and Saturday load conditions projected for ea.ch month for New York State in These dispatches indicated that the weekday loads can be divided into high and low load periods. For all months the high load period has a duration of about 14 hours and the low load period has a duration of about 1 hours. The weekend loads have a lower marginal unit energy cost than the weekday low load period. The marginal cost of energy for each of these periods for each month is described in Section 6. F- 29

45 +2 t I I I I I I I I NET INFLOW-GRASS ISLAND POOL-THOUSANDS OF C.F.S. Figure F-15 NIAGARA RIVER ADJUSTMENT TO AVERAGE MONTHLY ENERGY OUTPUT OF PRESENT CANADIAN POWER PLANTS FOR DAILY MEAN FLOW DEVIATION VERSUS INFLOW TO GRASS ISLAND POOL

46 55 vj LL I z 5 v) v) 9 5 a 5 a c3 > c3 CL W Z W a n TIME NIGHT LOSS NON-TOURIST """"----- """- ---""" TOURIST INFLOW TO GRASS ISLAND POOL-THOUSANDS C.F.S. Figure F- 16 N!AGARP, RlVER DA!LY ENERGY GA!N OR LOSS FROM OPERATION OF S.A.B. NO. 2 PUMP G.S. VERSUS INFLOW TO GRASS ISLAND POOL

47 The principal difference between the method used to compute the various energy components from Canadian plants and those from U.S. plants arises from the fact that it is satisfactory to consider that Ontario Hydro's pumped storage reservoir is filled and emptied daily, but for the PASNY pumped storage this would not be satisfactory. The method of computing the daytime, nighttime and weekend energy outputs from PASNY facilities is described in the following: (1) For each calendar month the total energy outputs in average Mw were computed for 2 to 25 Grass Island Pool inflows, which represent the expected flow range. For tourist season months, two values of energy output for each flow were computed, One of these values applies to the tourist hours and the other value applies to nontourist hours. The relationship between Grass Island Pool inflow and the three classes of energy outputs for each calendar month are shown on Figure$ F-17 to F-. (2) U.S. entitlement for each Grass Island Pool inflow was computed as described in (4). (3) The Grass Island Pool level was related to the flow as described in (3). (4) The waterways head loss between Grass Island Pool and the forebay canal was computed from the relationship 2 H = Q /K f where H = friction head loss f Q = PASNY diversion rate expressed in thousands of cfs K = waterways roughness factor which varies month by month as indicated by two years of hourly operating measurements. (5) The canal forebay level was computed as Grass Island Pool level less waterways head loss. (6) The energy outputs shown on Figures F-17 to F- assume a Moses plant tailrace elevation of 25.. This provides a gross head on the Moses plant equal to the difference between the forebay level described in i tem (5) and 25.O. (7) The Moses energy outputs shown on Figures F-17 to F- were computed from the diversion to Moses, in item (2) and gross head, (item (6)), using the turbine-generator output characteristics determined by Gibson tests. F-32

48 76 NOTE: DAYTIME=14 HR. 72 / NOUNITSON SCHEDULEDMAINTENANCE WEEKDAY 52 a LT a a Z a I? 4 z 2 3E f > E W z W 3; 2E 2L 2c 1f 1: E \. I 1 ) I I I GRASS ISLAND POOL INFLOW, TCFS Figure F-17 PASNY ENERGY-FLOW RELATIONSHIP JANUARY F- 33 I I 3 I 32

49 76 72 NOTE: DAYTIME=14 HR. NO UNITS ON SCHEDULED MAINTENANCE WEEKDAY TOTAL ---- WEEKEND DAY TOTAL a Q a a $, 4 I > L7 a 32 w Z w WEEKDAY DAYTIME WEEKDAY NIGHTTIME 2E 24 2c 1E li e L \. ( GRASS ISLAND POOL INFLOW, TCFS Figure F-I 8 PASNY ENERGY-FLOW RELATIONSHIP FEBRUARY F- 34

50 NOTE: DAYTIME=14 HR. 1 LPGP UNIT ON SCHEDULED MAINTENANCE WEEKDAY TOTAL ----WEEKEND DAY TOTAL a a CY - a 44 2 a I 9 4 I 5 36 f >. (I) 5 32 z W WEEKDAY DAYTIME - WEEKDAY NIGHTTIME c \ RESERVOIR RELEASE GRASS ISLAND POOL INFLOW, TCFS Figure F- 19 PASNY ENERGY-FLOW RELATIONSHIP MARCH F- 35

51 76 72 NOTE: DAYTIME=14 HR. 1 RMNPP UNIT ON SCHEDULED MAINTENANCE / / WEEKDAY TOTAL\ 7 -WEEKEND DAY TOTAL 48 a - 44 $ 4c 2 2 3c z > a 3; W z W WEEKDAY DAYTI ME 2t /WEEKDAY NIGHTTIME 21 / 2( 1( 1: RELEASE I GRASS ISLAND POOL INFLOW, TCFS Figure F- 2 PASNY ENERGY-FLOW RELATIONSHIP APRIL F- 36

52 NOTE: DAYTIME=14 HR. 1 LPGP UNIT ON SCHEDULED MAINTENANCE - / /,WEEKEND DAY TOTAL a [L < Z rr x 4 z 36 z & 32 LL W Z W \- WEEKDAY DAYTIME / WEEKDAY NIGHTTIME "- 4 a I I I I 1 I I I I I I GRASS ISLAND POOL INFLOW TCFS Figure F-21 PASNY ENERGY-FLOW RELATIONSHIP MAY - F-37

53 NOTE: DAYTIME=14 HR. 1 LPGP UNIT ON SCHEDULED MAINTENANCE / 64 TOTAL U a Z z l i = 4c 2 3f z - > 3; : W Z W DAY TI ME 2E 21 2( / / WEEKDAY NIGHTTIME 1t 1: I I I I I I I I I 1 I I 1 I, GRASS ISLAND POOL INFLOW, TCFS Figure F-22 PASNY ENERGY-FLOW RELATIONSHIP JUNE F-38

54 NOTE: DAYTIME=14 HR. NO UNITS ON SCHEDULED MAINTENANCE /' /I' "-WEEKEND DAY TOTAL 6 WEEKDAYTOTA a : Z a z > 2 32 W Z W.' WEEKDAY DAYTIME 24 2 / / WEEKDAY NIGHTTIME ". 3 MWHR EKDAY RESERVOIR RELEASE 8 4 \. \ GRASS ISLAND POOLINFLOW,TCFS Figure F-23 PASNY ENERGY-FLOW RELATIONSHIP JULY F- 39

55 76 72 NOTE: DAYTIME=14HR. NO UNITS ON / SCHEDULEDMAINTENANCE 68 TOTAL DAYTIME 48 a a LL - 44 z rr 5 4 I 8 $: 36 f > a E 32 z W 24 / 2 / WEEKDAY NIGHTTIME MWHR 12 RESERVOIRRELEASE r - - e \. 4 I C I 1 1 I 1 2 I 22 I I GRASS ISLAND POOL INFLOW, TCFS I Figure F- 24 PASNY ENERGY-FLOW RELATIONSHIP AUGUST F-4 \ I I

56 NOTE: DAYTIME=14 HR. 1 RMNPP UNIT ON SCHEDULED MAINTENANCE WEEKDAY 52 a rr a 48 Q: 44 Z a $ 4 E 2 36 Z - > LL 32 W z W 24 / / DAYTIME WEEKDAY NIGHTTIME RESERVOIR REL.EASE 8 4 C I I I I I I I 1 I I I I GRASS ISLAND POOL INFLOW, TCFS Figure F-25 PASNY ENERGY-FLOW RELATIONSHIP SEPTEMBER 1 12 F-41

57 NOTE: DAYTIME=14 HR. 1 RMNPP UNITON SCHEDULED MAINTENANCE / / 64 6 DAY TOTAL 56 WEEKDAY 52 4 a a 48 c Z u I g 4 2 3E f t u a: 32 W Z W WEEKDAY DAYTIME 2E 24 / / WEEKDAY NIGHTTIME 2c 1E 1; RELEASE E I ( I I 1 1 I I I I I I 1 I GRASS ISLAND POOL INFLOW, TCFS Figure F- 26 PASNY ENERGY-FLOW RELATIONSHIP OCTOBER F-42

58 76 " NOTE: DAYTIME=14HR LPGP UNIT ON SCHEDULEDMAINTENANCE 68 EKEND DAY TOTAL a 2a 44 WEEKDAY DAY17 ME Z mi $ f >. W 32 Z W c " RESERVOIRRELEASE \ 4 I I 1 I I I I I GRASS ISLAND POOL INFLOW, TCFS Figure F-27 PASNYENERGY-FLOWRELATIONSHIPNOVEMBER F-43 I I 3 I 32

59 NOTE: DAYTIME=14 HR. NO UNITS ON SCHEDULED MA1 NTENANCE a d 44 P Z & I 4 z 36 f > 32 WEEKDAY DAYTIME W Z w 2E 2L 2c If 1: t I I I I I I I I GRASS ISLAND POOL INFLOW, TCFS Figure F- PASNY ENERGY-FLOW RELATIONSHIP DECEMBER F- 44

60 (8) The maximum amount of water that can be discharged through a Moses plant unit for high head is controlled hy the maximum permissible generator output which is consideted to be 19 Mw. For gross heads less than 34 feet, the maximum unit discharge is controlled by the full gate flow. The canal forebay elevation was assumed to be limited to a minimum of 54.. (9) Thirteen Moses plant units were considered to be available each month, except during April, September and October when only twelve units were considered to be available to allow for maintenance. (1) The maximum diversion to Moses was the flow that would load the available Moses units to 19 Mw or to full gate discharge or produce a canal forebay level of 54., whichever is the least. (11) The magnitude of Lewiston Pump-Generator plant releases which can be made and the rate of nighttime river flow that can be converted to daytime energy by the use of this facility depends on the Grass Island Pool level, inflow and the corresponding Moses diversion. The amounts of daytime energy releases from the reservoir and nighttime energy stored in the reservoir for the range of Grass Island Pool inflows are also shown on Figures F-17 to F-. Reservoir releases cannot exceed the difference between the maximum discharge capacity of the available Moses units and the available river diversions for more than an hour or two without wasting water available for power, Hence, for high flows the daytime energy released from the reservoir is controlled by the margin between Moses discharge capacity and diversions. Reservoir releases, of course, cannot exceed the discharge capacity of the Lewiston-Pump-Generating units available. Since the Lewiston Pumped Storage Reservoir is used on a weekly cycle, it is the practice to limit the net reservoir drawdown in energy terms on a weekday to an average not exceeding about 3Mwh. For days when the flow is above the prevailing average, the net drawdown would be more. Thus, the daytime energy released from the reservoir for low flows was controlled by the maximum Lewiston discharge capacity when generating or the maximum total nighttime pumping, plus permissible net daily storage draft less pump-generation cycle loss, whichever was smaller. (12) For the basis-of-comparison and regulation plans Rot requiring a control structure at Lake Erie outlet, the outflow would vary somewhat erratically during the month. In order to obtain the daytime and nighttime energy outputs from the Authority's Niagara facilities for a given mean monthly flow, the sum of Moses and Lewiljton daytime output and the Moses less Lewiston pumping energy for nighttime output have been taken from the appropriate Figures F-17 to F- for 5 to 95 percent duration flows in 1 percent increments for the flow distribution for that particular mean monthly flow, The average of energy outputs for these ten duration increments has been computed and tabulated as the daytime and nighttime energy versus mean monthly Grass Island inflows for uncontrolled Lake Erie. In order to account for all hours of the week, the Saturday and Sunday energy available from a particular Grass Island Pool inflow was decreased by the amount F-45

61 which would be needed to refill Lewiston pumped storage reservoir for that flow. (13) For regulation plans requiring controlled Lake Erie outflows, the daytime energy output for a given mean monthly flow was found by adding the Moses plant energy output to the Lewiston pump storage daytime output. The nighttime output was found by subtracting the Lewiston pumping energy from the Moses nighttime energy, These values and the energy available over a weekend may be read directly from Figures F-17 to F- for a given flow. The figures referred to above were developed early in the study and are presented herein to graphically illustrate the methodology of energy evaluation. For the later studies, computer programs were utilized which used the same logic as the graphical method, but reduced the amount of time required to evaluate a given sequence of flows. (14) The actual Moses plant tailwater level depends upon Lake Ontario level and flow in the lower Niagara River. Therefore, the energy output for a given month was determined as described above and then adjusted by adding or subtracting 1/3th of the total energy for each foot by which the computed Moses tailwater was below or above elevation 25.. The Moses plant tailwater was computed as described in (6), plus a constant 2. feet to allow for the typical slope between the SAB and Moses plants Peak Capacity Output Computations for Canadian Plants The total peak capacity obtainable from Canadian plants depends primarily upon the flow available for power diversion. The output of interest is that obtainable at the time of system daily peak power demand. Since the available diversions and head vary with time, peak capacity obtainable is inherently a probability variable that can be expressed conveniently in terms of the percent of days for which the available output exceeds specified values, This representation of peak capacity available versus percent of time is analogous to the familiar flow duration curve. The method of computing the peak capacity is described in the following paragraphs. (1) The peak capacity from the Canadian plants has been related to Grass Island Pool inflow for each season, tourist and non-tourist. These relationships are shown graphically on Figure F-29. Each of the curves of this figure was derived by computing the capacity for 2 to 25 flows covering the expected flow range. (2) The diversions available to Canada for each flow were computed as described in Section (4). (3) The dispatch of water to the various plants was as described in Section (5,9,1). F-46

62 s 2-5a 19 - $ I I I- s a z a?1 P 4 $z 5 2 a I CURVESAPPLYTOPRESENTANDEXTENDEDCONTROLSTRUCTURE looo:o NOTE PEAKVALUES FROM CURVES DONOT io BASES $ la l:o A 1;o o1: 1:o l k l:o A 1;o 2Ao 2:o 2;o2:o INFLOW TO GRASS ISLAND POOL-1's 1. MEANNIAGARA RIVERWEEDEFFECT 2. MINIMUM S.A.B. NO. 2 FOREBAY S.A.B.NO. 2TW. ELEV. BASED ON MEAN LAKE ONTARIO ELEVATION ONTARIO POWER G.S. CAPACITY 8,3 CFS. (12 UNITS) 5. TORONTO POWERG.S. CAPACITY 9, CFS. (7 UNITS) 6. CANADIAN NIAGARA POWER OUT OF SERVICE CFS 21 2o : REQUIREADJUSTMENTS. 2Lo 2:o 2Ao 2Ao A 3fo NIAGARA AREA CANADIAN POWER PLANTS Figure F-29 TOTAL PEAK OUTPUT VERSUS INFLOW TO GRASS ISLAND POOL

63 (4) The SAB plant forebay level was determined from Figure F-13, Page F-27, using Grass Island Pool level corresponding to tke flow as described in Section (3) and the diversion dispatched to the Beck plant, but was limited to a minimum level of 54.. (5) The SAB plant tailwater level was determined from Figure F-3 which relates the tailwater level at the time of peak and the inflow to Grass Island Pool. This relationship was computed from Figure F-12, Page F-26, in xhich an average Lake Ontario elevation of was assumed. (6) Gross head on the SAB plants for peak capacity computations was the difference between the forebay level, item (4), and the tailwater level, item (5). (7) Combined SAB and pump-generating station peak capacity was computed as the maximum output that can be generated for 35 minutes over time of system peak demand and is based on computations made at 5- minute intervals over a period of one to one-and-one-half hours. The SAB diversion and forebay elevation at the beginning of the peaking period were computed as in (4) and (5) respectively, and the Beck tailwater elevation during the peaking period was computed as in item (5). It was assumed that the pump-generating station would be operated at maximum output with an initial storage reservoir elevation of 615. (8) Ontario Power plant peak capacity outputs were computed in the same way as described for energy computations, (9). (9) Toronto Power plant peak capacity outputs were computed in the same way as described for energy computations, (1). (1) The total peak capacity available from the Canadian plants for a given flow is the sum of the above outputs. It is this sum versus Grass Island Pool flow which is shown on Figure F-29 for tourist and non-tourist seasons requirements for Niagara Falls flows. (11) For each month the Grass Island Pool inflows which would be exceeded for certain percentage of days have been selected for the basisof-comparison condition and for each regulation plan. The percentages selected were 5 to 85 percent in 1 percent increments and 86 to 1 percent in one percent increments. For each of these flows, the peak capacity has been taken from Figure F-3. In this manner, available capacity versus percent of days for each calendar month for each flow condition to be studied has been developed. These computations cover the daily basis-of-comparison flows for the period January 1926 through December 1964 and a similar period for each regulation plan. The period January 1926 through December 1964 was used since daily Niagara River flows were only available after F-48

64 X 2 v zr; c\i 9 N m N 9 5: N (SS6I)al31--UV3d 9 rn* N 3 3Wll IV Z 'ON 'E'V'b IV 'A313 tl31vmllwl F-49

65 3.2.7 Peak Capacity Output Computations. for United States Plants The peak capactty obtainab.le from the Niagara Power Project of the Power Authority of the State of New York at any time depends upon flow available for power diversion, net head on the plants, number of generating units available for service after allowance for maintenance or forced outages, and the amount of water that can be released from the pumped storage reservoir. The output of interest is the peak capacity obtainable at the time of the system daily peak demand. Since each of the above factors which determined the daily peak capacity obtainable varies through time, peak capacity is inherently a probability variable that can be expressed conveniently in terms of the percent of days for which the available output exceeds specified values. To compute the peak capacity available versus time, relationships which exist among the determining factors, such as the relationship between flow available for power diversion and net head, must be taken into account and each of the independent factors must be expressed in terms of probability of percent of time. The effect of regulation would be to change the flow duration available for power diversion. The method of computing the peak capacity is described in the following paragraphs. (1) Grass Island Pool inflow duration listings for each calendar month for the basis-of-comparison and each regulation plan were prepared from the daily or monthly data as described in (2). (2) The diversion available to the United States for any given Grass Island Pool inflow was computed as described in (4). The percent of time each diversion would be available was developed from the Grass Island Pool inflow duration data. (3) Maximum Niagara Power Project output is reached when all available Lewiston Pumped Generating units are operated as generators at maximum output, For critical power system conditions, the pump generators would be used to help carry the daily peak load even if this meant diverting less water from the Niagara River than the U.S. entitlement at the time. For peak loads of one or two hours duration, operating experience has shown that it is usually possible to store such unused water temporarily in the upper Niagara River. For very low flow conditions, the maximum Niagara power output is limited by the amount of water which can be diverted from the Niagara River. (4) The amount of water which can be withdrawn from the pwnpedstorage reservoir and the amount of power which can be generated at the pump-generating plant depends upon the water level prevailing in the reservoir, A review of operating records indicated the suitability of the following reservoir level-probability relationship: F-5

66 Reservoir Water Probability of Being at Tabulated Surface Elevation Elevation at Time of System Daily peak Load 65.O % 4 % 1% 5% (5) It is established electric utility practice to provide periodic and systematic preventive maintenance for all generating units, The percent of time each of the 25 units at Niagara would be out of service for maintenance depends upon the maintenance interval, the number of shifts worked by maintenance personnel and the number of shifts required per unit to perform the necessary work, Present practice is an annual maintenance interval at the Lewiston plant and an 18-month interval at the Moses plant, which requires about 52 shift weeks of unit outage time per year to complete the work on all 25 units. Trial computer runs indicate that the least interference with Niagara peak power output would occur if the maintenance work for both plants were operated on a two shift per day basis with the Moses maintenance being accomplished in April, September and October and the Lewiston maintenance being accomplished in March, May, June and July. This maintenance schedule was used throughout for both the basis-ofcomparison and each regulation plan. (6) Average unit forced outage rate on each hydroelectric generating unit was assumed to be.5% in accordance with the United States National Power Survey recommendations. With this outage rate, the probability of each possible combination of generating units being in service was calculated, (7) For a given reservoir level, the maximum project capability is computed for all combinations of available diversions and forced unit outages, (8) The canal forebay level was computed as described in [4,5). (9) The net reservoir head was computed as one of the reservoir water levels given in the tabulation in item (4), less the canal forebay level described in item (8). (1) The maximum power and discharge from Lewiston Pump- Generating plant were computed using the above net head for each combination of units in service. (11) The discharge from Lewiston Pump-Generating plant was added to diversions available from the river. This is the maximum amount of water available for the Robert Moses Niagara power plant and may be more than can be used by the plant, If the diversion from the river F-51

67 and maximum Lewiston discharge exceeded the flow required for maximum Moses plant generation, the flow to be diverted from th.e river was reduced until maximum Moses plant generation was achieved. If the sum of Lewiston pump storage disdiarge and flaw- available from the river was insufficient to load all Moses units to full gate discharge, then flow was controlling, and computation output which can was made to determine the highest be achieved for that flow. (12) The tailwater level at Moses power plant was computed as for the Beck plant described in (5) and 2. feet was added to the SAB tailwater elevation to allow for the typical slope between the Beck and Moses plants. (13) The Moses plant output was computed for each combination of available water, gross head and units available. (14) Moses and Lewiston power outputs were added to obtain maximum project capacity. (15) For each combination of river flow, units available and effective reservoir water level, the maximum project capacity was computed as described above, The probability of the project output being controlled by any given set of conditions is the product of the independent probabilities of Lake Erie outflows, reservoir level and the unit outage configuration which resulted in that power. (16) The output corresponding to each possible set of Erie outflows, reservoir level and unit outage was computed in sequence until all possibilities were covered. The resuiting capacities were arranged in order and their probabilities accumulated to obtain a peak capacity versus the percent of days such capacity would be available. In this manner, available peak capacity versus percent of days for each calendar month for each flow condition studied was developed. These computations used the daily basis-of-comparison flows for the period January 1926 through December 1964 for the basis-of-comparison and flows for a similar period for each regulation plan. F-52

68 Section 4 MOSES-SAUNDERS (ST. LAWRENCE) POWER PLANTS 4.1 General Description There are two hydroelectric power plants in the International Section of the St. Lawrence River: The Robert H. Saunders Generating Station of Ontario Hydro and the Robert Moses Power Dam of the Power Authority of the State of New York. The rated head of both plants is 81 feet and each plant has 16 units and a total installed capacity of each plant is 912, kw. 4.2 Methodology for Determining Energy and Peak Capacity The peak and energy outputs obtainable from the Saunders plant and Moses plant were computed monthly (half monthly for April and December) over the 68-year period January 19 to December Monthly or halfmonthly energy outputs were divided into daytime (16 hours/day) and nighttime (8 hours/day) generation. The method of computing the total daytime and nighttime energy outputs and the total peak outputs each month or half-month is described in the following subsections Assumptions The assumptions adopted for computing the daytime energy, nighttime energy and capacity outputs for any given regulated mean monthly Lake Ontario outflow and level combination are as follows: (1) As the maximum operating efficiencies of the Saunders and Moses (St. Lawrence) units are essentially the same, the total or combined energy and peak capacity outputs from both plants were computed and divided equally between them. (2) The 1985 non-power flow diversions would consist of the estimated 1985 navigation requirements, the estimated 1985 Cornwall Canal requirements, and the Massena Canal requirements, which were assumed to be the same as those of They are summarized in Table F-2. The Massena and Cornwall canals bypass the power dam to supply water for municipal requirements and minimum flushing purposes for water quality conditions. The Cornwall municipal requirement is less than 5 cfs and for purposes of this study is neglected. (3) The navigation season extends from April 15 to December 15. (4) The daily peaking and weekly ponding test limits authorized by the International Joint Commission on a year-to-year basis are in effect. F-53

69 ~~~ ~~ TABLE F-2 ASSUMED 1985 NON-POWER FLOW DIVERSIONS Month Cornwall and Wiley-Dondero Canals (cfs) Municipal Water Re qui remen t s Massena Canal (cfs) Total (cfs) January February March April (1-15) (16-3) May June July August September October November December (1-15) (16-31) 5 1,2 2,4 2,7 2,8 2,7 2,6 2, ,7 1, ,23 2,43 2,73 2,83 2,74 2, ,64 2,73 1, Basic Data The basic data used are those presented in the Coordinated Data as Volume 2 to Appendix rfbf'. Basic Derived Data (1) Backwater slopes from Moses-Saunders forebay to Lake Ontario: For the open water season (April to December) backwater slopes were derived from a unit fall relationship between Oswego and the forebay, developed from observed levels and lake outflows over the period May 1959 to July The backwater slope curves are shown on Figure F-31. For the ice cover season (January to March) the backwater slopes were based on the results of design studies and model tests. They are shown on Figure F-32. (2) Tailwater stage-discharge relations: These relations have been derived for both open water and ice cover seasons from mean daily records of the Saunders and Moses plants tailwater elevations (averaged) and total plant discharge over the period June 1961 to September They are shown in graphical form on Figure F-33. F-54

70 246 r h m 4 v 6 -! c? 243 W v) 3 I K W B z l- a 2 J W WATER SURFACE ELEVATION AT LAKE ONTARIO (OSWEGO) I.G.L.D.(1955) _J 248 Figure F-31 BACKWATER SLOPES LAKE MOSES-SAUNDERS POWERHOUSE OPEN ONTARIO TO WATER CONDlTlONS F-55

71 v 5; 238 m, 9 -! r? - I I U W z g k a 236 II + a > w -l W u;l , W.S. ELEV. AT LAKE ONTARIO I.G.L.D.(1955) Figure F-32 BACKWATER SLOPES LAKE ONTARIO TO MOSES-SAUNDERS POWERHOUSE ICE COVER CONDITIONS F-56

72 16. r NOTE: TAILWATER IS AVERAGE OF MOSES-SAUNDERS TAILWATER ELEVATIONS. DISCHARGE IS COMBINED FLOWRECORDED THROUGH PLANTS I I I I 1 I I I DISCHARGE-THOUSANDS OFC.F.S. Figure F-33 TAILWATER STAGE-DISCHARGE CURVE

73 (3) Moses-Saunders total power-discharge-head relations: For the maximum efficiency operating range (total plant discharges of less than about, cfs) a relation between the average economy factor of the two plants and gross head was derived from unit performances actually attained in normal operation. This relation is shown graphically on Figure F-34. For the operating range beyond best efficiency (total plant discharges greater than about, cfs) a family of curves relating total plant output to discharge for a range of gross heads between 74 and 88 feet was derived from unit rating tables. These curves are shown on Figure F Determination of Capacity of St. Lawrence Plants (1) The Moses-Saunders forebay elevation, applicable to both daytime and nighttime energy and to peak, was determined from backwater slope curves relating Lake Ontario level and outflow to forebay level. The Lake Ontario levels and outflows used in the determinations were the regulated mean monthly or half-monthly values given in the basic data. The forebay level was limited to a maximum elevation of 242. and a minimum elevation of (2) The total plant discharge for peak determination was computed as the Lake Ontario regulated mean monthly or half-monthly outflow, less the estimated 1985 non-power flow diversions, plus 3, cfs up to a total of, cfs during the navigation season (April second half to December first half) or plus 38, cfs up to a total of 3, cfs during the non-navigation season (December second half to April first half). The total plant discharges for daytime and nighttime energy determinations were computed as the Lake Ontario regulated outflows less the estimated 1985 non-power flow diversions, plus 15, cfs during the daytime or minus 3, cfs during the nighttime. The effect of weekly ponding upon energy production during the non-navigation season was ignored because it was not considered to be,significant. (3) Moses-Saunders tailwater elkvations for computing peak output and daytime and nighttime energy outputs were determined from tailwater stage-discharge relations, Figure F-33, using the appropriate total plant discharge obtained as in item (2). (4) Gross heads for computing peak output and daytime and nighttime energy outputs were determined by subtracting from the forebay elevations obtained in item (2) the appropriate tailwater elevation obtained in item (3) (5) Total capacity output was determined from a family of curves relating total plant output, discharge and head or, if the coordinate of head and discharge does not fall within the limits of these curves, by reading from the curve (Figure F-34) relating average economy factor (kw/cfs) to gross head, the appropriate economy factor and multiplying it by the total plant discharge. The peak output of the Saunders plant or the Moses plant was one half of the total peak output. F-58

74 LL Q u I GROSS HEAD-FEET Figure F-34 AVERAGE ECONOMY FACTOR FOR MOSES-SAUNDERS PLANTS VERSUS GROSS HEAD (BEST EFFICIENCY OPERATING RANGE)

75 DERIVED FROM UNIT RATING TABLES / I 5 18 n I- 3 I- z 15 n I TOTAL PLANT FLOW-THOUSANDS OFCFS 32 -I 33 Figure F-35 COMBINED MOSES-SAUNDERS PLANT OUTPUT- DISCHARGE RELATIONSHIP F-6

76 4.2.5 Determination of Total Daytime and Total Nighttime Energy outputs Total daytime and total nighttime energy outputs in Mw-hrs were determined in the same manner as total peak output using the appropriate plant discharges and gross heads. These outputs were multiplied by the number of hours in the month or half-month that daytime or nighttime energy is produced (day - 16 hours x number of days, night - 8 hours x number of days) and the resultant values divided by two to give the daytime energy and the nighttime energy in Mw-hrs generated by the Saunders plant or the Moses plant. F-61

77 Section 5 BEAUHARNOIS-CEDARS (ST. LAWRENCE) POWER PLANTS 5.1 General Description The Beauharnois-Cedars developments are in Canada, in that part of the St. Lawrence River referred to as the Soulanges section. This comprises the 15-mile stretch between Lake St. Francis and Lake St. Louis in which there is a total drop of 82 feet. The drop occurs in three series of rapids separated by intervening pools of smooth water. At the outlet of Lake St. Francis are the Coteau Rapids which extend for one mile and fall 2 feet into a four-mile stretch of smooth water reaching to the head of Cedars Rapids. Over the next two miles, the Cedars Rapids fall 35 feet into a smooth section which flows four miles to the Cascades Rapids which discharge into Lake St. Louis, a fall of 27 feet. To harness the energy of the water in this turbulent reach, control dams were constructed at the exit from Lake St. Francis to allow the flow to be diverted from the natural channel into a canal excavated on the south shore called the Beauharnois Power and Navigation Canal. After passing through the Beauharnois Canal and the 8-foot drop at the Beauharnois Powerhouse, situated at the outlet end of the canal, the water is discharged into Lake St. Louis. Figure F-36 shows the relationship of the canal to the St. Lawrence River. The canal is 15 miles long and 3,3 feet wide, and the average depth is more than 3 feet. The navigation channel which is 6 feet wide and has a minimum depth of 27 feet is located along the left bank of the canal. Two locks permit navigation to pass from the canal to Lake St. Louis. The Cedars Generating Station came into service in 1914 with a capacity of 81, kilowatts from nine units. Other units were added as required until the plant reached its present capacity of 162, kilowatts from 18 units in At that time, it was the largest hydroelectric generating station in the world. It was planned to construct the Beauharnois powerhouse in three stages to keep pace with growing demand on the electrical system. Designed to have a capacity of 538,4 kilowatts from 14 generating units, the first stage rapidly took form and by the end of 1932, four units and two auxiliary units were in service. On August 25, 1951 the first units of the second stage were brought into service and all 12 units were in operation by the end of 1953 bring total capacity at Beauharnois to 1,21,76 kilowatts. to The first generating unit of Beauharnois 3 came into service in June 1959, with the last unit installed in early F-62

78 I Figure F-36 PLAN OF SOULANGE SECTION OF ST. LAWRENCE RIVER

79 The Beauharnois powerhouse now has 36 turbines for a total capacity of 1,574, kilowatts, excluding the two auxiliary units. 5.2 Methodology for Determining Energy Output at Beauharnois-Cedars Power Plants The following assumptions, data and computation method were used in the determination of the energy output at the Beauharnois-Cedars power plants Assumptions The Cedars Generating Station was assumed to have a minimum economic flow of 1, cfs and constant head of 42.5 feet Basic Data The basic data comprise monthly mean outflows of Lake Ontario and Lake St. Louis from the Coordinated Basic Data, Volume 2, Appendix rcb1r Derived Data (1) Lake St. Francis outflow is derived from a linear relationship between Lake Ontario outflow and Lake St. Francis outflow (Figure F-37), which in effect, combined Lake Ontario outflow with the local inflow downstream to Lake St. Francis. (2) The division of the Lake St. Francis outflow between Beauharnois-Cedars, Beauharnois navigation locks and water which is unavailable for power production due to seepage, overflow, etc., was as follows : The sum of the navigation requirements and the estimated water losses was subtracted from the monthly mean Lake St. Francis outflow (Table F-3). Since it was considered that a flow of 1, cfs at Cedars Generating Station is the minimum economic flow, this figure was subtracted from the total available discharge. The remaining available discharge was compared to the maximum permissible discharge at Beauharnois, (Table F-4). Should the calculated Beauharnois discharge exceed the permissible discharge, the difference is transferred to Cedars giving a Cedars discharge of 1, cfs plus this difference. Similarly, the calculated discharge at Cedars was compared to the maximum permissible discharge (Table F-4). Should the calculated Cedars discharge exceed the permissible discharge, then the calculated discharge was reduced to the value of the permissible discharge, and the excess water was spilled. (3) The working head for Beauharnois was determined as follows: The elevation of the Upper Beauharnois Lock was determined from a relationship between the upper lock levels and the corresponding Lake St. Francis discharges (Figure F-38) and the elevation of Lake St Louis was determined from the Lake St. Louis stage-discharge relationship F-64

80 V m s? 3 LC c 3 a 2 23 z W Y U -I 2 1 Y=IAKE ONTARIOUTFLOW CFSx13 X=LAKE ST. FRANCIS OUTFLOW CFS X LAKE ST. FRANCIS OUTFLOW x 13 CFS Figure F-37 DISCHARGE RELATIONSHIP BETWEEN LAKE ST. FRANCIS OUTFLOW AND LAKE ONTARIO OUTFLOW F-65

81 TABLE F-3 ESTIMATED 1985 NON-POWER FLOW REQUIREMENTS AT BEAUHARNOIS-CEDARS Month Navigation Requirement (cfs) Other Requirements (cfs) Total (cfs) January February March Apri May June July August September October November December Annual Average F-66

82 TABLE F-4 MAXIMUM PERMISSIBLEDISCHARGE AT BEAUHARNOIS AND CEDARS POWER PLANTS Month January February March April May June July August September October Nov emb er December Beauharnois (cfs) 16, 185, 185, 25, 25, 25, 25, 25, 25, 25, 25, 185, Cedars (cfs) 3, 5, 5, 6, 6, 6, 6, 6, 6, 6, 6, 5, Annual Average 226, 25 55, F-67

83 X=ELEVATION Y =OUTFLOW CFS x ELEVATION OF UPPER BEAUHARNOIS LOCK IGLD (1955) Figure F-38 RELATIONSHIP BETWEEN TOTAL LAKE ST. FRANCIS OUTFLOW AND ELEVATION OF UPPER BEAUHARNOIS LOCK F-68

84 which comprised two relationships: one for the open water period April to November inclusive, and one for the winter period December to March (Figure F-39). The difference between the elevation of the Upper Beauharnois Lock and Lake St. Louis gives the head at Beauharnois. (4) The power-discharge-head relationship for Beauharnois was based on recorded values of head, discharge and equivalent power output for the years 1962, 1963 and 1964 (Figure F-4). (5) A straight line relationship was used in relating Cedars power output to discharge, at a mean head of 42.5 feet (Figure F-41) Computation of Power Output Given the monthly mean outflows from Lake Ontario and Lake St-Louis, the following data were computed for each month: (1) Lake St. Francis outflow, from the relationship between Lake St. Francis and Lake Ontario outflows (Figure F-37). (2) The division of Lake St. Francis outflow between the Beauharnois and Cedars plants is described in (2). (3) The Beauharnois forebay elevation is obtained from the relationship between the Lake St. Francis outflow and the elevation at the Upper Beauharnois Lock (Figure F-38). (4) The Beauharnois tailwater elevation, from the Lake St. Louis stage-discharge relationship (Figure F-39). (5) The gross head at Beauharnois is obtained by subtracting the tailwater elevation from the forebay elevation. (6) Power output at Beauharnois is obtained by using the powerhead-discharge relationship for that plant, and at Cedars by using its power-discharge relationship determined for an average head of 42.5 feet (Figures F-4 and F-41). F-69

85 m 4 X F- 7

86 145 - H=78.. (Y + 841) =(X + 11,513) - (11,546) r 1 II I a w 3 CURVES PLOTTED FROM RECORDED DATA 15 - Y=OUTPUT MW X=FLOW CFS X I I FLOW AT BEAUHARNOISX 13 CFS Figure F-4 POWER OUTPUT-HEAD-DISCHARGE RELATIONSHIP FOR BEAUHARNOIS POWERHOUSE F- 71

87 m m * * m m m N N Lo 4 El c9 N m F- 72

88 Section 6 DETERMINATION OF UNIT ENERGY AND CAPACITY VALUES 6.1 Energy and Capacity Values In the light of very large increases in the costs of fuel for thermal power generation during recent years, there is considerable uncertainty associated with the long term cost of fuel and the value of energy and capacity in the future. Because meaningful projections of these values in the future cannot be made, it was decided that current (1971) rather than projected power costs would be used to evaluate the regulation plans. The energy and capacity values used in the study for evaluating the effects of regulation on the hydroelectric power generation are shown in Table F-5. TABLE F-5 ENERGY AND CAPACITY VALUES USED FOR EVALUATING EFFECTS OF REGULATION PLAN ON HYDROELECTRIC POWER GENERATION Energy Values (mills per kwh) Day Night Week-End Upper Michigan 8. 8.O *** 5.3 New York State Ontario *** Quebec 6. 6.O *** ** *Values based on 1971 costs. **Ice conditions limit the flow at the time the system experiences peak loads. ***Weekend values not applicable. 6.2 Upper Michigan System Generating facilities owned or controlled by Edison Sault Electric Company are insufficient to meet the needs of the area served and the Company purchases power from Consumers Power Company with which it is F- 73

89 interconnected, Evaluations of regulation plans were on the basis that the difference in power production by the existing hydroelectric power plants on the United States side of St. Marys River between any. regulation plan and the basis-of-comparison would be identical to the difference in power purchases from Consumers Power Company between the basisof-comparison and the regulation plan. 6.3 Ontario System In previous sections the methods were given for determining the peak and energy production that would result in the Ontario Great Lakes hydroelectric plants from the basis-of-comparison and the application of various regulation plans, From these computations the incremental peak (capacity) and energy at these plants from the regulation plans as compared to the basis-of-comparison were determined. As all these plants do now, and will do in 1985, feed into the Ontario grid, it is the effect on the Ontario system that must be assessed in evaluating from a power standpoint the benefit or otherwise of the regulation plans. Thus the effects at the individual plants must be evaluated and the net effect on the system determined Ontario East Load In evaluating the effect of a regulation plan on the 1985 system it was necessary to predict the composition of that system. To do this the nature and magnitude of the 1985 load,must first be estimated and the system selected to suit this load. The year 1985 was considered to include the period July 1, 1985 to June 3, 1986, as all new equipment was assumed to be in operation by July 1 in any year, On this basis the estimated 1985 load is shown in Table F-6. TABLE F-6 ESTIMATED LOAD (Mw) Most Probable Most Probable Time Period Peak Demand Interruptible Firm Peak Demand 21,38 July 1985 Dec, Feb 26, ,86 May ,3 27,67 26,35 23,51 F- 74

90 It was also assumed that the present seasonal and hourly pattern of load would continue to apply in the period July 1985 to June The Great Lakes- Power Company plant on the St. Marys River was assumed, for the purposes of the study, to be in the Ontario East system as any deficiencies must be made up from this system Ontario East System In selecting a power system to meet the 1985 load, it was necessary to predict the composition and characteristics of the system and the reserves that will be necessary at that time, To arrive at the 1985 system, a program for generation development additional to that in existence as of December 1968 was synthesized to the year The generation estimated to be in service in 1985 comprised all existing generation, generation already committed for construction and new hydroelectric and thermal units, The latter were 75 megawatt and 1, megawatt coal-fired and nuclear units respectively. In determining the capacity required criteria and assumptions were observed: in 1985, the following (1) The loss of load probability in any month in 1985 should not be greater than one day in ten years. Note: The loss of load computation follows the method described in the publication "Application of Probability Methods to Generation Capacity Problems", AIEE Subcommittee on Application of Probability Methods - Transaction 196. Since the highest load months are December-January, these months may be expected to govern the installation, However, provision must be made for all required scheduled maintenance so that the loss of load probability in the other months does not exceed the criterion of one day in ten years, (2) All new generation would be in operation by July 1, (3) In the loss of load probability computations, the load distribution curve for December-January was based only on normal working day peak loads, and the distribution curve of available output from generating stations was computed taking into account forced outages of thermal units and the variation in power output of the St, Marys, Niagara and St. Lawrence plants. (4) The forced outage rates of thermal units in successive years of operation are assumed to be: F- 75

91 First Second hi rd Year Year Year - 1. All thermal units 537 Mw and smaller 6% 8% 4% 2. For all 75 and 1, 12.5% Mw units thermal 8.75% 5% (5) It was assumed that there is complete correspondence between the peak outputs of the St. Marys, Niagara and St, Lawrence plants; i.e., the coincident peak output of the St. Marys and St, Lawrence plants was high or low at the same time that the peak output of the Niagara plants was high or low, (6) In addition to the reliability criteria in (l), an excess of capacity was required roughly equal to the largest unit scheduled for service each year (i,e., to protect against one new unit failing to meet its in-service date), As a result of these computations, the inventory of generation is given in Table F Ontario East system TABLE F-7 GENERATION INVENTORY ONTARIO EAST SYSTEM Type Capacity of Existing Units - December 1968 (Mw) Capacity of Units to be Added (Mw) Combustion Turbines Diesel 321 and 7 St. Lawrence Niagara 2,962 and All other hydraulic, including pump-generating stations and purchases 2, thermal Coal-fired 8,729 hermal Nuclear 18 16,2 9,939 25,787 Total F- 76

92 6.3.3 Determination and Evaluation of System Peak Increments The assessment of any regulation plan as compared to the basis-ofcomparison from a peak power standpoint, was determined by comparing the load meeting capability of the system in each case. If the load meeting capability of the system under a plan of regulation during the critical load period was greater than for the basis-of-comparison, then the installed capacity of the system could be reduced by a like amount and the value of the reduction credited to the regulation plan, The load meeting capability of the system was defined as the load that can be carried during the critical load period of December-January in the Ontario system, with a loss of load probability of one day in ten years having regard for the forced outage rates of the various components and the reserves detailed in Section above. As the peak differences are generally small in relation to the system capacity, it was necessary to make a precise computation to achieve valid comparisonsc As the 1985 Ontario East system arrived at in Section was synthesized by the addition of large blocks of capacity, it necessarily was somewhat greater in load meeting capability than the 1985 load. Therefore, for determination of increments of peak capacity for the basis-of-comparison and regulation plans, the precise load meeting capability of the system described in was computed and differences or increments established, In each case the determination of load meeting capability was based on a study of the duration curve of such capability during the critical December-January period. The corresponding duration curves during other months of the year were also examined to ensure that, even with reduced loads, a more critical period did not exist because of scheduled maintenance. A computer program was developed for this study. Based on the results of the above study, a load meeting capabi.lity was established for the basis-of-comparison and for the various regulation plans from which differences or increments were determined. In the Ontario system these were evaluated at $15. per kw per annum which was 1971 cost. It should be emphasized that the determination of relatively peak differences in very large systems is beyond the accuracy of the study methods and, therefore, the results in absolute values cannot be accurate. However, as the same method was applied to the basis-ofcomparison and all regulation plans, the differences thus determined may be reasonably representative of the differences in abilities of the regulation plan to provide system peak capacity. small Evaluation of System Energy Increments For each month of 1985, the generation available for loading purposes was determined, having in mind scheduled maintenance. Estimates were made of the load duration curves for all hours in each of three groups of days; working days, Saturdays and Sundays. Loading was then allocated to the various generation sources for each of the above groups of days, in each month of the year, for selected sets of coincident energy outputs from the hydroelectric plants. This procedure F-77

93 was followed for the basis-of-comparison and each regulation plan, to produce the lowest thermal cost. The value of incremental energy from the hydroelectric plants in each of these periods was determined from the value of displaced thermal or nuclear plants, and weighted values for daytime and nighttime periods in each month were then obtained. The resulting values of incremental energy throughout the year, based on 1971 costs, are 4.5 mills/kwh for daytime (16 hours/day) and 4.4 mills/kwh for nighttime (8 hours/day). 6.4 New York System In this section are presented the methods developed by the Power Authority of the State of New York (PASNY), the U.S. Army Corps of Engineers and the Federal Power Commission for computing the value of energy and power obtainable from hydroelectric power plants in the United States which use the waters of the Niagara and St. Lawrence Rivers, The basis-of-comparison of the energy and peak capacity that would result from a repetition of basis-of-comparison supplies to the Great Lakes is as described in Section 1.3. For a given regulation plan, the energy and peak capacities were those which would result from the same supplies and diversions but with levels and outflows controlled by the rules of that regulation plan. It should be emphasized that these methods were developed for the purpose of determining the economic benefit or loss which would result from implementing each of the regulation plans in comparison with the basis-of-comparison. Thus, interest is focused upon the change in value of energy and capacity which would accompany such regulation rather than upon the absolute value of the total outputs. All energy and capacity evaluations for this study were made within the framework of the estimated demand for electrical power and the generating equipment that is expected to be available to meet this demand in Determination of the Value of Energy in New York (1) An inventory of all existing units and a list of all future units expected to be in service to supply the New York power system requirement in 1985 was prepared. (2) The expected cost of energy from each of these generating sources was assigned from experience and judgement. (3) The value of week-day daytime, week-day nighttime and week-end energy for each month was developed by dispatches of the available system energy sources into typical daily load patterns for each month. These dispatches in New York included both Niagara and St, Lawrence available energy. The average unit value of the hydroelectric energy was taken as the cost that would accrue if a similar amount of energy were produced by the least expensive option available with the system F- 78

94 reserve equipment, The estimated unit value of energy for each month for each of these three categories is shown on Table F-5. (4) The energy for a particular monthly flow was obtained from assumation of the following: the available week-day daytime energy for a month times its estimated average per unit value plus the available week-day nighttime energy for a month times its estimated average per unit value plus the available week-end energy for a month times its estimated average per unit value. (5) The sum of all the monthly values for total PASNY St. Lawrence energy under plan 1958-D, when divided by 65 (number of years on record) gives the average annual PASNY St. Lawrence energy value for the basisof-comparison. The basis-of-comparison energy value for the U.S. Niagara plants was determined by applying the appropriate unit values to the energy quantities previously determined for the 5, 15, 25, etc., percent duration frequencies for each calendar month under the basisof-comparison. The average of the resulting values was the average annual energy value for the basis-of-comparison. (6) The same procedure outlined above in (5) was used to evaluate energy for each regulation plan, based on the energy quantities determined under the regime of levels and flows prescribed by the plan evaluated. (7) The annual average energy benefit or detriment of a given regulation plan was the difference between the energy value for that plan and the energy value for the basis-of-comparison Determination of the Value of Peak Capacity in the New York System (1) The computations described in items 3 and 4 of Section provided peak capacity duration listings from Niagara and the Moses St. Lawrence projects respectively. In view of the strong interdependence between the flows at the two projects and hence in their peak capacity, the peak capacity ordinates of the two projects were added for each duration to obtain a composite peak capacity versus duration. This process was followed to obtain the peak capacity duration listing for the basis-of-comparison and for each regulation plan. (2) A regulation plan could affect the availability of peak power by different amounts for various percentages of time. This being the case, a method was required to appraise the influence this variable effect could have upon the New York power system. (3) The growth of power demand in New York is expected to require continual additions of generating units to the system. The amount of capacity that would be needed to provide a satisfactory level of service is dependent to a degree upon the amount of power which is likely to be available from Niagara and St. Lawrence at the time of each day's peak load. The criterion for satisfactory service presently F- 79

95 in use by the utilities is that the probability of coincident outages large enough to impair meeting system loads should not exceed one day in ten years. The effect of changing peak capacity durations available from Niagara and St. Lawrence from those available for the basis-ofcomparison to those which would be available from the of flows a given regulation plan could be condensed to a single megawatt quantity by focusing attention on the amount of generating capacity other than Niagara and St. Lawrence that would be needed to secure the desired degree of service reliability in the state. The difference in the generating capacity needed for a given regulation plan in comparison with the capacity needed for the basis-of-comparison was a measure of effect on generating plant investment that would be saved by adopting that regulation plan with all other conditions unchanged. (4) Computation of the total generation required to satisfactorily supply the estimated 1985 New York power demands was carried out as Estimates were prepared of the expected power requirement in the state for These estimates were made by the Federal Power Commission in collaboration with the electric utilities serving New York State. These data include expected peak load for each month, load patterns for twelve bi-hourly periods for each peak week-day, average week-day, Saturday and Sunday, distributions of the maximum daily peak loads within each month and annual peak load for each year between 197 and An inventory of all existing generators presently existing in New York State was prepared. Units which were expected to be retired before 1985 were removed from the inventory and all announced new units were added to the inventory. The total generating capacity shown on the updated inventory in Table F-9, of course, does not provide enough capacity to carry the estimated 1985 peak load. Beyond the completion of the last announced new unit the addition of 5, 75 and 1, megawatt units has been assumed at a rate which would provide a normal reserve margin about the estimated annual peak load each year. In this way, a projection of the generators expected to be operating in New York State in 1985 has been prepared. This projection provided the size, age, and type of all such generators in service. These data permit assignment of a typical forced outage rate to each unit in accordance with Table F-8. The data on this table are the recommendations of the New York Power Pool except that the outage rates for hydroelectric units were taken from the U.S. National Power Survey since it was based upon much broader experience with respect to hydroelectric units. F-8

96 TABLE F-8 FORCED OUTAGE RATES IN NEW YORK SYSTEM Type Size (Mw) Forced Outage Rate (%) Immature Units (First 3 Years) Mature Units Fossil Fuel O O Nuc 1 ear Fue O O Gas Turbine and Internal Combustion All sizes 4. 2.o Hydroelectric All sizes.5 F-81

97 TABLE F-9 PROJECTED INVENTORY OF GENERATION IN THE NEW YORK SYSTEM IN 1985 SPe Capacity of Existing Units Not Retired (Mw) Capacity of Units to be Added (Mw) Internal Combustion Gas Turbine Small Hydro Power Authority State of New York Hydroelectric Plants ,12 Fossil Thermal Nuclear Pumped Storage 11, ,973 3,742 16, ,65 TOTAL IN ,38 Mw F-82

98 The outage rate was thus assigned to each generator and with the individual outage rate assigned, the total system generator listing, except Niagara St. and Lawrence, was analyzed for the probability of coincident forced outages of all possible magnitudes. These outages were subtracted from the total capacity to obtain a load carrying capacity versus probability of the capacity not affected by Great Lakes flows and levels. The above load carrying capacity-probability is merged with the St. Lawrence Niagara output-probability described in Section (16) to obtain the total load carrying capacity in New York State versus probability. The probability of generating capacity available for service was compared with the probability of peak load for a particular calendar month to determine what probability exists of load exceeding available generation. If this probability analysis showed that available generation would be inadequate to carry the load fre- more quently than one day in ten years, more generating capacity was indicated and another or unit a larger unit was inserted into the projected generator installation. This analysis proceeded by successive trials until each calendar month was supplied with enough generating capacity to meet the expected loads with the probability of loss of load because of insufficient generation limited to almost exactly one day in ten years. The amount of generation required varies with the monthly power demands. Of course, during months of relatively light power requirements, the capacity not needed to carry load can be taken out of service for maintenance. The capacity finally required must be adequate to carry the 1985 annual and monthly peak load as well as provide enough time for maintenance of all units. U.S. The National Power Survey indicates that 8 1/2% of the time should be allowed for scheduled maintenance outages. If the variation in monthly peak loads does not automatically provide enough maintenance time, then equipment above that needed to meet the annual peak load would be required to permit the necessary maintenance outages. ' total generating capacity needed in York New to carry the 1985 loads with a given regulation plan as compared to the generation needed to carry the loads with the same degree of reliability for the basis-of-comparison indicates the amount of generating capacity that would not have to be provided if that particular regulation plan were put into effect. The dollar value of this saving was computed as the difference in kilowatts times the cost of providing an equivalent amount of capacity of a comparable nature for the New York State system. F-83

99 6.5 Quebec System 6.5.1General In this section the method of estimating power values from the effects of Great Lakes regulation St. Lawrence River generating stations in Quebec was based on information supplied by the Quebec Hydroelectric Commission Determination of Capacity and Energy Values (1) Capacity - At Beauharnois, the flow in the canal must be reduced to approximately 16, cfs during the ice forming period each winter. At Cedars, a flow of 3, cfs is the maximum permitted during the ice forming period. The dependable capacity of the Beauharnois and Cedars powerhouses during the of time the maximum load demand on the Quebec system is, therefore, limited by ice forming conditions rather than by upstream regulation. For this reason, no power evaluation was made with respect to dependable peak capacity. (2) Energy - With respect to energy, however, a redistribution of flow from upstream regulation may increase or decrease total energy output for the Beauharnois and Cedars stations. The reasons for this are related to the fact that Beauharnois Generating Station has a rated head of 8 feet, and flows in excess of 25, cfs must be diverted to the Cedars Station with a head of only 42 feet. Thus, outflows from Lake Ontario upstream in excess of 25, cfs will be utilized at a lower head with resulting lower energy production. The value of loss or gain in energy to Hydro-Quebec at the Beauharnois and Cedars Stations was assumed at 6. mills/kwh. F- 84

100 Section 7 EVALUATION OF REGULATION PLANS 7.1 General This section presents the results of the detailed evaluations made by the Power Subcommittee of the several selected regulation plans for the lake combinations Superior-Ontario (SO) regulated, Superior-Erie- Ontario (SEO) regulated, Superior-Michigan-Huron-Ontario (SMHO) regulated and Superior-Michigan-Huron-Erie-Ontario (SMHEO) regulated. Each plan was evaluated according to the methodology outlined in Sections 2 and 6 using the basis-of-comparison as described in Section 1.3. For the evaluations in this section, the different system configurations and the different evaluation methods developed are unlikely to produce similar system response to regulation. The benefits or losses are shown in the detailed evaluation tables. It is emphasized that the benefits or losses shown must be considered in terms of the size of the system or in terms of the total energy produced. Changes in capacity of 1 to 3 Mw are negligible in a system load of 3,3 to 4, Mw. However when considering the Upper Michigan system the magnitude of the changes due to regulation is about 6 percent of total output value. No evaluation was made of capacity in the case of the Beauharnois and Cedars plants since their ability to meet maximum load demand in December is limited by flow restrictions during ice formation rather than regulation. 7.2 Lakes Superior and Ontario Regulation Plans The plan of regulation selected for detailed evaluation is designated SO-91. The results of this evaluation are shown on Tables F-1 to F-16. The net annual effect on power generation is a benefit of about $64,. This effect varies between power systems. The annual loss of $16, for the Upper Michigan system is significant in relation to the relatively small local power system involved. However, the total annual benefits of $46, and $26, for the New York State and Ontario systems are small in relation to the size of the respective systems, Similarly, the annual increase in energy of plan SO-91 to the Beauharnois-Cedars results in a benefit of $8, which is small compared to the total power generated. The following is a review of the effects of plan SO-91 on each of the power systems involved. These effects are summarized in Table F-1. F-85

101 : I lo n.l z r( 4, 3.. I I L $ ": 3 a L Q, I z T 4 a w b 4 a N In IPJ k w E.d cdo m u a TJ. *(In MOO* In Mlco MOM 1 omam a F-86

102 7.2.1 Province of Ontario Determination of energy outputs from the Ontario plants was made for each month of the period 19 to 1967 assuming first the basis-ofcomparison and then regulation by plan SO-91 respectively in effect throughout the period. The average daytime and nighttime monthly energy outputs over the period were computed for the R.H. Saunders plant on the St. Lawrence River, for the Niagara area plants and for the St. Marys River plants. The average annual energy production from the three groups of plants for both the basis-of-comparison and plan SO-91 and their differences are shown in equivalent dollar values in Table F-11. The total average energy benefit to the Ontario plants from plan SO-91 is $14,. The effect on the Ontario system capacity of regulation plan SO-91 was analyzed using the loss of load probability method. The results (Tables F-11 and F-12) indicate that plan SO-91 would produce a gain in peak capacity on the system of 8 Mw, which has an equivalent annual value of $12, Province of Quebec The calculated annual benefit shown on Table F-13 of plan SO-91 to the Quebec system is $8,. Most of the effects resulting from a change in Lake Superior regulation would be essentially dissipated by the intervening lakes and by the regulation of Lake Ontario under plan 1958-D before they reach the Beauharnois and Cedars plants and any benefit would be coincidental with the supplies to the intervening lakes New York State Energy outputs from existing major hydro installations in New York State were determined for the spectrum of levels and flows which occurred on Lakes Erie and Ontario from 19 through 1967, for both basis-of-comparison conditions and for plan SO-91. December 197 unit values for energy, in dollars per Mwh, were applied to the appropriate incremental differences in energy output between SO-91 and the basis-of-comparison, for three distinct periods of time; weekday daytime, weekday nighttime and weekends. These values are shown in Table F-5. The dollar values of differences in energy under plan SO-91 for the St. Lawrence plant and Niagara plants are shown in Table F-14. The total average annual benefit to energy production for New York plants would be $22,. F-87

103 TABLE F-11 REGULATION PLAN SO-91 COMPARED TO BASIS-OF-COMPARISON ONTARIO SYSTEM VALUE OF DIFFERENCE IN AVERAGE DAYTIME AND NIGHTTIME ENERGY PRODUCTION AND IN 1985 PEAK LOAD MEETING CAPABILITY Daytime Nighttime 7 Month St. Lawrence Niagara St. Marys Total St. Lawrence Niagara St. Marys Total ($1 January + 2,2 + 6,7 + 8,9 + 2,2 + 3,3 + 5,5 February + 2, + 8,1 +1, 1 + 1, + 4, + 5, March + 4,5 + 6,7 +11,2 + 2,2 + 3,3 + 5,5 Apri 1 May June + 8,6 + 8,6 + 3,2 + 3,2 + 4,5 + -2,2 6,7 + 9, + 3,3 + 3,3-1,1 + 5,5 + 2,2 + 4,3-2,2 + 4,3 + 3,2-1,1 + 2,1 July + 2,2 + 2,2 + 4,4 + 1,1 + 4,4 + 5,5 August + 2,2 + 4,5 + 6,7-1,1 + 4,4 + 3,3 September + 4,3 + 4,3-1,1 + 3,2 + 2,1 October + 6,7 +2,2 + 8,9-3,3 + 4,4 +1,1 + 2,2 November + 8,6 + 8,6-3,2 + 5,3 + 2,1 December + 8,9 + 8,9 + 4,4 + 4,4 93,9-2,2 +76,3 +19,8 Total +46,4-1,1 +46,4 + 1,1 Total, Day and Night: St. Lawrence +$2,9 Niagara +$122,7 St. Marys -63,3 = All +$14,3 Value of Difference in 1985 Peak and Load Meeting Capability = +$12, (December)

104 TABLE F- 12 REGULATION PLAN SO-91 COMPARED TO BASIS-OF-COMPARISON ONTARIO SYSTEM AVERAGE MONTHLY ENERGY PRODUCTION AND 1985 PEAK LOAD MEETING CAPABILITY Month January February March Apri 1 May June Ju 1 y August September October November December January February March Apri 1 May June July August September October November December January February March Apri 1 May June July August September October November December Average Daytime Energy Average Nighttime Energy Plan Basis-of- Plan Basis-of- Plants at Comparison SO-91 Diff. Comparison SO-91 Diff. (Av. Mw) (Av. Mw) (Av. Mw) (Av. Mw) (Av. Mw) (Av. Mw) N I AGARA 1,874 1,862 1,9 1,611 1,678 1,682 1,65 1,624 1,67 1,59 1,874 1,896 ST. LAWRENCE ST. MARYS ,877 1,866 1,93 1,615 1,681 1,684 1,651 1,626 1,69 1,593 1,878 1, PEAK LOAD MEETING CAPABILITY (Mw) Month Basis-of-Comparison Plan SO-91 Diff. December 3,3 +8 3,38 F- 89

105 TABLE F-13 REGULATION PLAN SO-91 COMPARED TO BASIS-OF-COMPARISON HYDRO QUEBEC BEAUHARNOIS AND CEDARS PLANTS AVERAGE MONTHLY AND ANNUAL ENERGY OUTPUTS AND ANNUAL VALUE OF ENERGY DIFFERENCE (Av. kw) Month Basis-of- Comparison Plan SO-91 Difference January February March 1,54,963 1,238,232 1,233,12 1,55,24 1,24,16 1,235, ,9 +2,595 Apri 1 May June 1,372,873 1,389,331 1,425,972 1,376,8 1,395,7 1,4,553 +3,415 +5,956 +2,581 July August September 1,456,472 1,475,436 1,476,512 1,459,748 1,477,646 1,476,473 +3,276 +2,21-39 October November December 1,449,882 1,411,165 1,24,2 1,447,379 1,48,89 1,24,822-2,53-2, Annua 1 1,353,497 1,351,997 6 mills/kwh benefit = $8, F-9

106 TABLE F-14 REGULATION PLAN SO-91 COMPARED TO BASIS-OF-COMPARISON NEW YORK STATE SYSTEM VALUE OF AVERAGE MONTHLY AND ANNUAL ENERGY PRODUCTION -IY Month ( P Basis-ofso-91 Comparison Niagara Plants Plan ($1,) Diff. January 8,981 9,9 February 8,47 8, March 71 9,661 9,732 Apri 1 7,78 7, ,629 May 8,632-3 June 8, 199 8, July 8, 387 8,379-8 August 8, 163 8,158-5 September 7,46 7, October 7,542 7,538-4 November 57,757 7,87 December 8,889 8,92-31 Basis -of - Comparison 3,493 3,433 3,847 3, 793 4,19 3,875 4,143 4,162 3, 84 3,976 3,155 3,6 St. Lawrence Plants Plan so-91 3,498 3,437 3,862 3,793 4,32 3,877 4,156 4,164 3,83 3,974 3,154 3,6 Benefit Average Annual in 17 $1, 5 Diff

107 Table F-15 shows the improvement to Power Authority capacity under SO-91. The average excess capacity of 13 Mw under SO-91 indicates that with this plan in effect, the overall system would be required to install 13 Mw less than it would under basis-of-comparison conditions. At the 1971 rates assumed for Power Authority financing, the indicated savings would be $24, per year. As shown in Table F-1, the total average annual benefit to the New York State system under plan SO-91 would be $46, Upper Michigan Plan SO-91 produces an increase in the period of time during which the flows would be equal to or above 7, cfs. This excess water cannot be utilized by the present plants. This plan reduces the time the flows are below 7, cfs, The two changes combine to produce an average energy loss of $13,. A small capacity loss ($3,) results from an increase in the period of time that the flows are at a minimum. The resultant total loss of $16, (Table F-16) represents about 6% of the total output value. 7.3 Lakes Superior, Erie and Ontario Regulation Plan (SEO) The following paragraphs present a summary of the detailed economic evaluation of plan SEO-33 as compared to the basis-of-comparison for the power interests. The overall annual net benefit to power generation due to plan SEO-33 was computed to be $31,; however, not all of the power systems involved realize benefits. There would be an annual loss of $16, to the Upper Michigan system which would be significant in relation to the relatively small local power system involved. The annual effect on the Beauharnois and Cedars plants of the Quebec system would be a benefit of $1,. There would be total annual benefits of $24, and $22, for the New York State system and the Ontario system respectively. A summary of the effects of plan SEO-33 on power is provided in Table F-17. Since the plan SEO-91 is essentially the SO-91 regulation plan with dredging in the Niagara River to permanently lower Lake Erie levels, the Niagara River flows are the same as SO-91. The benefit to power would be essentially the same as SO-91 and no detailed evaluation for power was made Province of Ontario Determination of energy output from the Ontario plants was made for each month of the period of record for first the basis-ofcomparison and then plan SEO-33. The average daytime and nighttime monthly energy outputs over the period of record were computed for the R.H. Saunders plant at the St. Lawrence River, for the Niagara area plants and the St. Marys River plant. The average annual energy production from the three groups of plants for both the basis-of- F-92